UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
☒ Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2024 or
☐ Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Commission File Number 0-53713
OTTER TAIL CORPORATION
(Exact name of registrant as specified in its charter)
Minnesota (State or other jurisdiction of incorporation or organization) | 27-0383995 (I.R.S. Employer Identification No.) | ||||
215 South Cascade Street, Box 496, Fergus Falls, Minnesota (Address of principal executive offices) | 56538-0496 (Zip Code) | ||||
Registrant's telephone number, including area code: 866-410-8780
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||
| Common Shares, par value $5.00 per share | OTTR | The Nasdaq Stock Market LLC | ||||||
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer ☑ | Accelerated Filer ☐ | ||||||||||||||||
Non-Accelerated Filer ☐ | Smaller Reporting Company ☐ | Emerging Growth Company ☐ | |||||||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑
As of June 30, 2024, the aggregate market value of common stock held by non-affiliates was $3,545,374,386.
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date: 41,827,999 Common Shares ($5 par value) as of January 31, 2025.
DOCUMENTS INCORPORATED BY REFERENCE
The Registrant's definitive Proxy Statement for its 2025 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.
| TABLE OF CONTENTS | |||||||||||
| Description | Page | |||||||
| ITEM 1. | ||||||||
| ITEM 1A. | ||||||||
| ITEM 1B. | ||||||||
| ITEM 1C. | ||||||||
| ITEM 2. | ||||||||
| ITEM 3. | ||||||||
| ITEM 3A. | Information About Our Executive Officers (as of February 19, 2025) | |||||||
| ITEM 4. | ||||||||
| ITEM 5. | ||||||||
| ITEM 6. | ||||||||
| ITEM 7. | ||||||||
| ITEM 7A. | ||||||||
| ITEM 8. | ||||||||
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34) | ||||||||
| ITEM 9. | ||||||||
| ITEM 9A. | ||||||||
| ITEM 9B. | ||||||||
| ITEM 9C. | ||||||||
| ITEM 10. | ||||||||
| ITEM 11. | ||||||||
| ITEM 12. | ||||||||
| ITEM 13. | ||||||||
| ITEM 14. | ||||||||
| ITEM 15. | ||||||||
| ITEM 16. | ||||||||
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| DEFINITIONS | |||||||||||
The following abbreviations or acronyms are used in the text:
ADP | Advanced Determination of Prudence | kV | kiloVolt | |||||||||||
| AFUDC | Allowance for Funds Used During Construction | kW | kiloWatt | |||||||||||
| AME | Available Maximum Energy | kwh | kilowatt-hour | |||||||||||
| ARO | Asset Retirement Obligation | LSA | Lignite Sales Agreement | |||||||||||
| ARP | Alternative Revenue Program | MDT | Metering and Distribution Technology | |||||||||||
| ASC | Accounting Standards Codification | MISO | Midcontinent Independent System Operator | |||||||||||
BSER | Best System of Emission Reduction | MPUC | Minnesota Public Utilities Commission | |||||||||||
| BTD | BTD Manufacturing, Inc. | MW | Megawatt | |||||||||||
| CCMC | Coyote Creek Mining Company, L.L.C. | NAV | Net Asset Value | |||||||||||
CCR | Coal Combustion Residual | NDDEQ | North Dakota Department of Environmental Quality | |||||||||||
| CDD | Cooling Degree Day | NDPSC | North Dakota Public Service Commission | |||||||||||
| CIS | Center for Information Security | NERC | North American Electric Reliability Corporation | |||||||||||
CO2 | Carbon dioxide | Northern Pipe | Northern Pipe Products, Inc. | |||||||||||
CODM | Chief Operating Decision Maker | NOx | Nitrogen Oxides | |||||||||||
| COSO | Committee of Sponsoring Organizations of the Treadway Commission | OTC | Otter Tail Corporation | |||||||||||
DOE | U.S. Department of Energy | OTP | Otter Tail Power Company | |||||||||||
DOJ | U.S. Department of Justice | PFAS | Polyfluoroalkyl substances | |||||||||||
| ECO | Energy Conservation and Optimization Rider | PIR | Phase-in Rider | |||||||||||
| EEI | Edison Electric Institute | PSLRA | Private Securities Litigation Reform Act of 1995 | |||||||||||
| EEP | Energy Efficiency Plan | PTCs | Production tax credits | |||||||||||
| EPA | Environmental Protection Agency | PVC | Polyvinyl chloride | |||||||||||
| ERISA | Employee Retirement Income Security Act of 1974 | RHR | Regional Haze Rule | |||||||||||
| ESSRP | Executive Survivor and Supplemental Retirement Plan | ROE | Return on equity | |||||||||||
| EUIC | Electric Utility Infrastructure Costs Rider | REC | Renewable Energy Certificate | |||||||||||
| FASB | Financial Accounting Standards Board | RRR | Renewable Resource Rider | |||||||||||
| FCA | Fuel Clause Adjustment | RTOs | Regional Transmission Organizations | |||||||||||
| FERC | Federal Energy Regulatory Commission | SDPUC | South Dakota Public Utilities Commission | |||||||||||
| FOB | Free on Board | SEC | Securities and Exchange Commission | |||||||||||
| GCR | Generation Cost Recovery Rider | SIP | State Implementation plan | |||||||||||
| GHG | Greenhouse Gas | SO2 | Sulfur Dioxide | |||||||||||
| HDD | Heating Degree Day | SOFR | Secured Overnight Financing Rate | |||||||||||
HDPE | High-Density Polyethylene | SPP | Southwest Power Pool | |||||||||||
| ICSP | Information and Cybersecurity Program | T.O. Plastics | T.O. Plastics, Inc. | |||||||||||
| IRP | Integrated Resource Plan | TCR | Transmission Cost Recovery Rider | |||||||||||
IT | Information Technology | TSR | Total Shareholder Return | |||||||||||
ITC | Investment Tax Credits | VIE | Variable Interest Entity | |||||||||||
JTIQ | Joint Targeted Interconnection Queue | Vinyltech | Vinyltech Corporation | |||||||||||
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| WHERE TO FIND MORE INFORMATION | ||||||||
| FORWARD-LOOKING INFORMATION | ||
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PART I
| ITEM 1. | BUSINESS | |||||||||||||
Otter Tail Corporation (OTC) is a holding company which has strategically invested in a portfolio of diversified operations including an electric utility and manufacturing and plastic pipe businesses with corporate offices located in Fergus Falls, Minnesota and Fargo, North Dakota.
We classify our five operating companies into three reportable segments consistent with our business strategy and management structure. The following table depicts our three segments, and the subsidiary entities included within each segment:
| ELECTRIC SEGMENT | MANUFACTURING SEGMENT | PLASTICS SEGMENT | ||||||||||||
| Otter Tail Power Company (OTP) | BTD Manufacturing, Inc. (BTD) | Northern Pipe Products, Inc. (Northern Pipe) | ||||||||||||
| T.O. Plastics, Inc. (T.O. Plastics) | Vinyltech Corporation (Vinyltech) | |||||||||||||
Electric includes the generation, purchase, transmission, distribution and sale of electric energy in western Minnesota, eastern North Dakota and northeastern South Dakota. Otter Tail Power (OTP), our primary business since 1907, serves approximately 134,000 customers in more than 400 communities across a predominantly rural and agricultural service territory.
Manufacturing consists of businesses engaged in the following manufacturing activities: contract machining; metal parts stamping; fabrication and painting; and production of plastic thermoformed horticultural containers, life science and industrial packaging, material handling components and extruded raw material stock. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States.
Plastics consists of businesses producing polyvinyl chloride (PVC) pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the western half of the United States and Canada.
Throughout the remainder of this report, we use the terms "Company," "us," "our," or "we" to refer to OTC and its subsidiaries collectively. We will also refer to our Electric, Manufacturing and Plastics segments and our individual subsidiaries as indicated above.
INVESTMENT AND GROWTH STRATEGY
Our investment and growth strategy is focused on our electric utility as our foundational business, complemented by our investments in our Manufacturing and Plastics segments (collectively, our Manufacturing Platform). This strategic diversification allows us to maintain a moderate risk profile while driving growth through rate base investments in our Electric segment and organic growth opportunities in our Manufacturing Platform. This strategy and risk profile are designed to provide a more predictable earnings stream, to provide growth over long-term cycles, to produce returns above the utility industry average, to support investment grade credit ratings, and to provide for dividend payments to our shareholders.
Our long-term focus remains on executing our strategy to grow our business and achieving operational, commercial and talent excellence to strengthen our position in the markets we serve. Our long-term financial objectives include achieving a compounded annual growth rate in earnings per share in the range of 6 to 8%, with a long-term earnings mix of approximately 65% from our Electric segment and 35% from our Manufacturing Platform. We also are targeting an annual increase in our dividend to be in the range of 6 to 8%. We expect our earnings growth and cash flow generation to be driven by rate base investments in our Electric segment and from existing capacities and recent investments within our Manufacturing and Plastics segments.
Since 2021, our earnings mix has diverged from our long-term target of 65% from our Electric segment and 35% from our Manufacturing Platform and our earnings growth rate has exceeded our long-term targeted growth rate primarily due to market conditions within the PVC pipe industry. These conditions have led to significant revenue, earnings and cash flow growth in our Plastics segment. Currently, we expect these industry conditions to gradually normalize through 2027. As they do, we expect earnings and cash flow generation within our Plastics segment to moderate from current levels. Once these industry conditions have normalized, we expect to achieve our long-term financial objectives as outlined above.
We will continue to review our business portfolio to identify additional opportunities to improve our risk profile, enhance our credit metrics and generate additional sources of cash to support the organic growth opportunities in our Electric, Manufacturing, and Plastics segments. We will also evaluate opportunities to allocate capital to potential acquisitions. We are a committed long-term owner and do not acquire companies in pursuit of short-term gains. However, we will divest of businesses which no longer fit into our strategy and risk profile over the long term.
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We maintain a set of criteria used in evaluating the strategic fit of our operating businesses. The operating company should:
•Maintain a minimum level of net earnings and a return on invested capital in excess of the Company’s weighted-average cost of capital,
•Have a strategic differentiation from competitors and a sustainable cost advantage,
•Operate within a stable and growing industry and be able to quickly adapt to changing economic cycles, and
•Have a strong management team committed to operational and commercial excellence.
Our actual mix of earnings for the years ended December 31, 2024 and 2023 along with an historical average and long-term expectation are shown below:
HUMAN CAPITAL
Our employees are a critical resource for our business 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. We monitor various metrics and objectives associated with i) employee safety, ii) workforce stability, iii) management and workforce demographics, iv) leadership development and succession planning v) productivity, and vi) employee engagement. We have established the following in furtherance of these efforts:
Safety - Safety is one of our core values. In managing our business, we focus on the safety of our employees and have implemented safety programs and management practices to promote a culture of safety. Safety is also a metric used and evaluated in determining annual incentive compensation. We continually monitor the Occupational Safety and Health Administration Total Recordable Incident Rate (number of work-related injuries per 100 employees for a one-year period) and Lost Time Incident Rate (number of employees who lost time due to work-related injuries per 100 employees for a one-year period). New cases are reported and evaluated for corrective action during monthly safety meetings attended by safety professionals at all locations. Our 2024 Total Recordable Incident Rate was 1.64, compared to 1.70 in 2023 and our Lost Time Incident Rate was 0.16 in 2024, compared to 0.53 in 2023.
Employee and Leadership Development, Succession Planning and Training Programs - We invest in training and professional development for employees, management and leaders throughout the Company to ensure all have the necessary training and skills to perform their work well, and to build enterprise-wide understanding of our culture, strategy and processes. Annual succession planning, individual development planning, mentoring, and supervisory and leadership development programs all play a role in ensuring a capable leadership team now and in the future. Our skill progression and technical training programs help to retain a stable and skilled workforce.
Workforce Stability - Recruiting, retaining and developing employees is an important factor in our continued success and growth. We regularly evaluate our recruiting programs, employee retention and turnover rates.
Employee Engagement - To enhance the effectiveness of our workforce and to help our companies continue to be places where our employees choose to work and thrive, we have undertaken a multi-year series of employee engagement surveys. We use the feedback to help shape the employee programs of our organization.
Human Rights - We are committed to the protection of our employee’s freedom of expression and freedom of organization and assembly.
Inclusive Workplace - We hold every employee accountable for their behavior in maintaining a workplace free of discrimination and harassment. We have implemented education initiatives for all employees, aimed at inclusive leadership and a respectful workplace.
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Code of Business Ethics - We require employees to complete training on several topics associated with our code of business ethics to reinforce our commitment to compliance with laws, regulations and values that guide who we are and how we do business.
As of December 31, 2024, we employed 2,133 full-time employees as shown in the table below:
| Segment/Organization | Employees | ||||
| Electric Segment | |||||
OTP (1) | 798 | ||||
| Manufacturing Segment | |||||
| BTD | 960 | ||||
| T.O. Plastics | 162 | ||||
| Segment Total | 1,122 | ||||
| Plastics Segment | |||||
| Northern Pipe | 93 | ||||
| Vinyltech | 82 | ||||
| Segment Total | 175 | ||||
| Corporate | 38 | ||||
| Total | 2,133 | ||||
(1) Includes all full-time employees of Otter Tail Power Company, including employees working at jointly owned facilities. Labor costs associated with employees working at jointly owned facilities are allocated to each of the co-owners based on their ownership interest. | |||||
As of December 31, 2024, 371 employees of OTP were represented by local unions of the International Brotherhood of Electrical Workers under two separate collective bargaining agreements expiring on August 31, 2026 and October 31, 2026. OTP has not experienced any strike, work stoppage or strike vote, and considers its present relations with employees to be good. None of the employees of our other operating companies are represented by local unions.
| ELECTRIC | Contribution to Operating Revenues: 39% (2024), 39% (2023), 38% (2022) | ||||
OTP, headquartered in Fergus Falls, Minnesota, is a vertically integrated, regulated utility with generation, transmission and distribution facilities to serve its approximately 134,000 residential, commercial and industrial customers in a service area encompassing approximately 70,000 square miles of western Minnesota, eastern North Dakota and northeastern South Dakota.
CUSTOMERS
Our service territory is predominantly rural and agricultural and includes over 400 communities, most of which have populations of less than 10,000. While our customer base includes relatively few large customers, sales to commercial and industrial customers are significant and in 2024 two customers combined accounted for 19% of segment operating revenues.
The following charts summarize our retail electric revenues by state and by customer segment for the years ended December 31, 2024 and 2023:
In addition to retail revenue, our Electric segment also generates operating revenues from the transmission of electricity for others over the transmission assets we wholly or jointly own with other transmission service providers, and from the sale of electricity we generate and sell into the wholesale electricity market.
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COMPETITIVE CONDITIONS
Retail electric sales are made to customers in assigned service territories. As a result, most retail customers do not have the ability to choose their electric supplier. Competition is present in some areas from municipally owned systems, rural electric cooperatives and, in certain respects, from on-site generators and co-generators. Electricity also competes with other forms of energy.
Competition also arises from customers supplying their own power through distributed generation, which is the generation of electricity on-site or close to where it is needed, designed to meet specific, local needs. The adoption of distributed generation can be impacted by the availability of tax credits associated with the development and use of distributed energy. Distributed energy resources can include combined heat and power, solar photovoltaic, wind, battery storage, thermal storage and demand-response technologies.
The degree of competition may vary from time to time depending on relative costs and supplies of other forms of energy and advances in technology. Irrespective of the competitive environment, we are focused on providing value to our customers and ensuring our retail rates remain among the lowest in the region and in the nation. In 2024, our summer residential rates were 16% below the regional average and 30% below the national average.
The following table presents our average retail rate per kilowatt-hour (kwh) by customer class and in total for the years ended December 31, 2024 and 2023:
| Revenue per kwh | 2024 | 2023 | |||||||||
| Residential | 11.38 | ¢ | 10.82 | ¢ | |||||||
| Commercial & Industrial | 7.03 | ¢ | 7.02 | ¢ | |||||||
| Total Retail | 7.98 | ¢ | 7.90 | ¢ | |||||||
Wholesale electricity markets are competitive under the Federal Energy Regulatory Commission (FERC) open access transmission tariffs, which require utilities to provide nondiscriminatory access to all wholesale users. In addition, the FERC has established a competitive process for the construction and operation of certain new electric transmission facilities under federal regulation. Certain states, including the three states in our service territory, have laws which provide the incumbent transmission owner the right of first refusal to construct and own new transmission facilities. Future changes to the laws which provide for the right of first refusal could impact the competitive conditions related to the construction of new transmission facilities.
OTP has franchises to operate as an electric utility in substantially all of the incorporated municipalities it serves. Franchise rights generally require periodic renewal. No franchises are required to serve unincorporated communities in any of the three states OTP serves.
GENERATION AND PURCHASED POWER
OTP primarily relies on company-owned generation, supplemented by power purchase agreements, to supply the energy to meet our customer needs. Wholesale market purchases and sales of electricity are used as necessary to balance supply and demand. Our mix of owned generation and wholesale market energy purchases to meet customer demand are impacted by wholesale energy prices and the relative cost of each energy source with wholesale market energy being utilized when it is determined to be beneficial to customers.
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As of December 31, 2024, OTP’s wholly or jointly owned plants and facilities, as well as in place power purchase agreements, and their dependable kilowatt (kW) capacity were:
| Capacity / Purchased Power in kW | ||||||||
| Owned Generation: | ||||||||
| Baseload Plants | ||||||||
Big Stone Plant(1) | 264,700 | |||||||
Coyote Station(2) | 151,200 | |||||||
| Total Baseload Plants | 415,900 | |||||||
| Combustion Turbine and Small Diesel Units | ||||||||
| Astoria Station | 288,800 | |||||||
Solway | 50,000 | |||||||
| All Other | 77,900 | |||||||
| Total Combustion Turbine and Small Diesel Units | 416,700 | |||||||
| Owned Wind Facilities (rated at nameplate) | ||||||||
| Merricourt | 150,000 | |||||||
| Ashtabula III | 62,400 | |||||||
| Luverne | 49,500 | |||||||
| Ashtabula | 48,000 | |||||||
| Langdon | 40,500 | |||||||
| Total Owned Wind Facilities | 350,400 | |||||||
Hoot Lake Solar (rated at nameplate) | 49,900 | |||||||
| Hydroelectric Facilities | 1,000 | |||||||
| Total Owned Generation Capacity | 1,233,900 | |||||||
Power Purchase Agreements: | ||||||||
| Purchased Wind Power (rated at nameplate and greater than 2,000 kW) | ||||||||
| Edgeley | 21,000 | |||||||
| Langdon | 19,500 | |||||||
| Total Purchased Wind | 40,500 | |||||||
| Total Generating Capacity | 1,274,400 | |||||||
(1) Reflects OTP's 53.9% ownership percentage of jointly owned facility. | ||||||||
(2) Reflects OTP's 35.0% ownership percentage of jointly owned facility. | ||||||||
The following charts summarize the percentage of our generating capacity by source, including owned and jointly owned facilities and through power purchase arrangements, as of December 31, 2024 and 2023:
Under the Midcontinent Independent System Operator (MISO) requirements, OTP is required to provide sufficient capacity through wholly or jointly owned generating capacity or power purchase agreements to meet its monthly weather-normalized forecast demand, plus a reserve obligation. MISO operates under a seasonal resource adequacy construct in which generation resources are accredited and planning reserve margin requirements are implemented on a seasonal basis. Current planning reserve margin requirements range between 9.0% and 33.9%, depending on the season.
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The following charts summarize the percentage of retail kwh sold by source during the years ended December 31, 2024 and 2023:
Capacity Additions
As part of our investment plan to meet our future energy needs, the following projects are under development or construction:
Wind Energy Facility Upgrades consist of the replacement and upgrade of hubs, gearboxes, blades, generators and other components of our Ashtabula, Ashtabula III, Langdon and Luverne wind facilities at a total cost of approximately $230 million. Once complete, we expect the increased energy production from these facilities will be equivalent to an additional 40 megawatts (MW) of generation. Our Langdon facility upgrades were completed in the fourth quarter of 2024 and we anticipate the remaining facilities will be completed in 2025. Once complete, the energy production from each of these facilities is eligible for production tax credits (PTCs) over a ten-year period. We expect these projects will lower customer costs through a combination of fuel savings and the tax credit benefits afforded to our customers.
Solway Solar is a solar facility currently under development that is planned to be constructed adjacent to our existing Solway natural gas plant in northern Minnesota. The project is expected to add an additional 50 MW of generating capacity. We estimate the facility will be operational by the end of 2026 and OTP's capital investment is estimated to be $100 million. The recovery of the costs of this project remains subject to regulatory approval.
Abercrombie Solar is solar facility currently under development in southeastern North Dakota. In October 2024, we entered into a purchase agreement to acquire the development assets of the project, including approximately 3,400 acres of land, interconnection agreements, state and local permits, and all other assets of the project. We anticipate we will close on the purchase of the development project in late 2025 or early 2026 and estimate the facility will be operational by the end of 2028. Once complete, the facility is expected to have a generating capacity of 295 MW. OTP's capital investment in the project is estimated to be $450 million. The recovery of the costs of this project remains subject to regulatory approval.
ENERGY TRANSITION
OTP is transitioning to a lower-carbon and increasingly clean energy future, while maintaining affordable and reliable electricity to serve our customers. We have developed the following goals in furtherance of our efforts to support the energy transition:
Own or purchase energy generation that is 55% renewable by 2030.
Reduce carbon emissions from owned generation resources 50% by 2030 from 2005 levels.
Reduce carbon emissions from owned generation resources 97% by 2050 from 2005 levels.
We have undertaken numerous initiatives to reduce our carbon footprint and mitigate greenhouse gas (GHG) emissions in the process of generating electricity for our customers. Our recent initiatives include adding the 49 MW Hoot Lake Solar facility to our resource mix, the investment in our wind energy facility upgrades, the commencement of development of the 50 MW Solway Solar and 295 MW Abercrombie Solar facilities, and sponsoring energy conservation programs.
From 2005 through 2024, we have reduced our carbon dioxide (CO2) emissions approximately 40% and increased the amount of renewable generation resources we own or purchase through power purchase agreements by approximately 420 MW. We currently own or contract energy generation that is 37% renewable.
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The following chart depicts our energy resource mix, which is the electricity we used to serve our customers in 2005 and 2024, and the projected mix in 2030 and 2050. The amounts include energy generated from owned resources, procured through power purchase agreements and energy purchased in the wholesale market:
RESOURCE MATERIALS
Coal is the principal fuel burned at our jointly owned Big Stone and Coyote Station generating plants. Coyote Station, a mine-mouth facility, burns North Dakota lignite coal. Big Stone Plant burns western subbituminous coal. We source coal for our coal-fired power plants through requirements contracts which do not include minimum purchase requirements but do require all coal necessary for the operation of the respective plant to be purchased from the counterparty. Our coal supply contracts for our Big Stone Plant and Coyote Station have expiration dates in 2026 and 2040, respectively.
The supply agreement between the Coyote Station owners, including OTP, and the coal supplier includes provisions requiring the Coyote Station owners to purchase the membership interests and pay off or assume loan and lease obligations of the coal supplier, as well as complete mine closing and post-mining reclamation, in the event of certain early termination events and at the expiration of the coal supply agreement in 2040. See below and Note 1 to our consolidated financial statements included in this report on Form 10-K for additional information.
Coal is transported to Big Stone Plant by rail and is provided under a common carrier rate which includes a mileage-based fuel surcharge.
We purchase natural gas for use at our combustion turbine facilities based on anticipated short-term resource needs. We procure natural gas from multiple vendors at spot prices in a liquid market primarily under firm delivery contracts.
TRANSMISSION AND DISTRIBUTION
Our transmission and distribution assets deliver energy from energy generation sources to our customers. In addition, we earn revenue from the transmission of electricity over our wholly or jointly owned transmission assets for others under approved rate tariffs. As of December 31, 2024, we were the sole or joint owner of approximately 14,000 miles of transmission and distribution lines.
Midcontinent Independent System Operator
MISO is an independent, non-profit organization that operates the transmission facilities owned by other entities, including OTP, within its regional jurisdiction and administers energy and generation capacity markets. MISO has operational control of our transmission facilities above 100 kilovolts (kV). MISO seeks to optimize the efficiency of the interconnected system, provide solutions to regional planning needs and minimize risk to reliability through its security coordination, long-term regional planning, market monitoring, scheduling and tariff administration functions.
Transmission Additions
MISO Tranche 1.0. In 2022, MISO approved several projects within the first tranche of its long-range transmission plan. Within the first tranche of projects, OTP will be a partial owner of two new 345 kV transmission projects. These projects will be developed and constructed over several years and OTP's total investment in these projects is estimated to be $475 million.
Jamestown-Ellendale includes the construction of a new 345 kV transmission line in southeastern North Dakota spanning approximately 95 miles from Jamestown, North Dakota to Ellendale, North Dakota. This project is in the initial stages of planning and development and is expected to be completed in 2028.
Big Stone South-Alexandria-Big Oaks includes the construction of a new 345 kV transmission line in eastern South Dakota and western Minnesota and the addition of a second circuit to an existing 345 kV line in central Minnesota. The new transmission
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line will span approximately 100 miles between Big Stone, South Dakota and Alexandria, Minnesota. A second circuit will be added to the existing transmission line spanning from Alexandria, Minnesota to Big Oaks, Minnesota. This project is in the initial stages of planning and development and is expected to be completed in 2032.
MISO Tranche 2.1. In December 2024, MISO approved several projects within the second tranche of its long-range transmission plan. Within this second tranche of projects, we anticipate OTP will be a partial owner of three projects, including a new 345 kV transmission line, a new 765 kV transmission line, and the addition of a second circuit to an existing 345 kV transmission line. These projects will be developed and constructed over several years and OTP's total investment in these projects is estimated to be $700 million.
Bison-Alexandria includes the construction of a second 345 kV circuit, which is being added to an existing transmission line in eastern North Dakota and western Minnesota. This project is in the initial stages of planning and development and is expected to be completed in 2032.
Maple River-Cuyuna includes the construction of a new 345 kV transmission line in eastern North Dakota and western Minnesota, as well as investment in substation expansion. This project is in the initial stages of planning and development and is expected to be completed in 2033.
Big Stone South-Brookings County includes the construction of a new 765 kV transmission line in eastern South Dakota, as well as investment in substation expansion. This project is in the initial stages of planning and development and is expected to be completed in 2034.
Joint Targeted Interconnection Queue (JTIQ). In December 2024, MISO and Southwest Power Pool (SPP) approved a set of transmission projects that are part of a collaboration between MISO and SPP to construct high-voltage transmission lines along the MISO and SPP seam, which spans seven states - Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota and South Dakota. These projects will improve reliability and resolve constraints in the transmission system to allow for up to 30 gigawatts of new generation to be added to the system.
OTP expects to participate in one JTIQ project, being the sole owner of a new 345 kV transmission line spanning from Big Stone, South Dakota to Hankinson, North Dakota, and a partial owner of a new 345 kV line spanning from Hankinson, North Dakota to Bison, North Dakota. In October 2023, the U.S. Department of Energy (DOE) approved a grant in an amount up to 25% of the total JTIQ project costs. OTP's capital investment in these projects, after the impact of the 25% DOE grant, is estimated to be $450 million.
SEASONALITY
Electricity demand is affected by seasonal weather differences, with peak demand occurring in the summer and winter months. As a result, our Electric segment operating results regularly fluctuate on a seasonal basis. In addition, fluctuations in electricity demand within the same season but between years can impact our operating results. We monitor the level of heating and cooling degree days in a period to assess the impact of weather-related effects on our operating results between periods.
PUBLIC UTILITY REGULATION
OTP is subject to regulation of rates and other matters in each of the three states in which it operates and by the federal government for, among other matters, the interstate transmission of electricity. OTP operates under approved retail electric tariff rates in all three states it serves. Tariff rates are designed to recover plant investments, a return on those investments and operating costs. In addition to determining rate tariffs, state regulatory commissions also authorize return on equity (ROE), capital structure and depreciation rates of our capital investments. Decisions by our regulators significantly impact our operating results, financial position and cash flows.
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Below is a summary of the regulatory agencies with jurisdiction over OTP covered by each regulatory agency:
| Regulatory | ||||||||
| Agency | Areas of Regulation | |||||||
| Minnesota Public Utilities Commission (MPUC) | Retail rates, issuance of securities, depreciation rates, capital structure, public utility services, construction of major facilities, establishment of exclusive assigned service areas, contracts with subsidiaries and other affiliated interests and other matters. Selection or designation of sites for new generating plants (50,000 kW or more) and routes for transmission lines (100 kV or more). Review and approval of fifteen-year Integrated Resource Plan. | |||||||
| North Dakota Public Service Commission (NDPSC) | Retail rates, certain issuances of securities, construction of major utility facilities and other matters. Approval of site and routes for new electric generating facilities (>500 kW for wind generating facilities; >50,000 kW for non-wind generating facilities) and high voltage transmission lines (>115 kV). Review and approval of fifteen-year Integrated Resource Plan. | |||||||
| South Dakota Public Utilities Commission (SDPUC) | Retail rates, public utility services, construction of major facilities, establishment of assigned service areas and other matters. Approval of sites and routes for new electric generating facilities (100,000 kW or more) and most transmission lines (115 kV or more). | |||||||
| Federal Energy Regulatory Commission (FERC) | Wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, hydroelectric licensing and accounting policies and practices. Compliance with North American Electric Reliability Corporation (NERC) reliability standards, including standards on cybersecurity and protection of critical infrastructure. | |||||||
In addition to base rates, which are established through periodic rate case proceedings within each state jurisdiction, there are other mechanisms for recovery of our capital investments and operating costs between rate cases. The following table summarizes these recovery mechanisms:
| Recovery Mechanism | Jurisdiction(s) | Additional Information | ||||||||||||
| Fuel Clause Adjustment (FCA) | MN, ND, SD | Provides for periodic billing adjustments for changes in prudently incurred costs of fuel and purchased power. In North and South Dakota, fuel and purchased power costs are generally adjusted on a monthly basis. In Minnesota, fuel and purchased power costs are estimated on an annual basis and the accumulated difference between actual and estimated cost is refunded or recovered, subject to regulatory approval, in subsequent periods. | ||||||||||||
| Transmission Cost Recovery Rider (TCR) | MN, ND, SD | Provides for the recovery of costs outside of a general rate case for investments in new or modified electric transmission assets and certain MISO transmission service and related costs. | ||||||||||||
| Renewable Resource Rider (RRR) | MN, ND | Provides for the recovery of costs outside of a general rate case for investments in certain new renewable energy projects. | ||||||||||||
| Energy Conservation and Optimization Rider (ECO) | MN | Under Minnesota law, OTP is required to save 1.75% of its gross retail energy revenues through the energy conservation and optimization program. Recovery of these costs outside of a general rate case occurs through the ECO rider. | ||||||||||||
| Electric Utility Infrastructure Costs Rider (EUIC) | MN | Provides for the recovery of costs for investments made to replace or modify existing infrastructure if the replacement or modification conserves energy or uses energy more efficiently. | ||||||||||||
| Metering and Distribution Technology Cost Recovery Rider (MDT) | ND | Provides for the recovery of costs for advanced metering infrastructure, outage management systems and demand response projects. | ||||||||||||
| Generation Cost Recovery Rider (GCR) | ND | Provides for the recovery of costs outside of a general rate case for investments in new generation facilities. | ||||||||||||
| Energy Efficiency Plan (EEP) | SD | Provides for the recovery of costs from energy efficiency investments. | ||||||||||||
| Phase-In Rider (PIR) | SD | Provides for the recovery of costs outside of a general rate case for investments in new generation facilities and advanced grid infrastructure. | ||||||||||||
Resource Planning
Under Minnesota law, utilities are required to submit for approval by the Minnesota Public Utilities Commission (MPUC) a 15-year advance Integrated Resource Plan (IRP). An IRP is a set of resource options a utility could use to meet the service needs of its customers over the forecast period, including an explanation of the utility’s supply and demand circumstances, and the extent to
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which each resource option would be used to meet those service needs. The MPUC’s findings of fact and conclusions regarding IRPs are considered to be prima facie evidence, subject to rebuttal, in future rate reviews and other proceedings.
Under North Dakota law, utilities are required to submit for approval by the North Dakota Public Service Commission (NDPSC) a 15-year advance IRP every three years.
South Dakota does not have a formal advance IRP process.
Capital Structure Petition
Minnesota law requires an annual filing of a capital structure petition with the MPUC. In this filing, the MPUC reviews and approves OTP's capital structure. Once approved, OTP may issue securities without further petition or approval, provided the issuance is consistent with the purposes and amounts set forth in the approved petition. OTP’s current capital structure approved by the MPUC on July 30, 2024, allows for an equity-to-total-capitalization ratio between 47.2% and 57.7%, with total capitalization not to exceed $2.2 billion.
Renewable Energy Standard
Minnesota has adopted a renewable energy standard requiring utilities to generate or procure sufficient renewable generation such that the following percentages of total retail electric sales to Minnesota customers come from qualifying renewable sources: 25% by 2025 and 55% by 2035. Qualifying renewable sources are classified as wind, hydropower, hydrogen and certain biomass generation. We met the current renewable sources requirements with a combination of owned renewable generation and purchases from renewable generation sources. Minnesota law also requires 1.5% of total Minnesota retail electric sales by public utilities to be supplied by solar energy. For a public utility with between 50,000 and 200,000 retail electric customers, such as OTP, at least 10% of the 1.5% requirement must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 40 kW or less. We met the current solar requirement with a combination of owned solar generation and solar renewable energy certificate (REC) purchases. We plan to comply with the requirements of this standard in the future through a combination of our existing and projected renewable generation fleet.
Minnesota Clean Energy Law
In February 2023, Minnesota enacted the Clean Energy Law, which requires electric utilities to generate or procure sufficient electricity from carbon-free resources, to provide retail customers in Minnesota with at least the following percentages of carbon-free electric energy: 80% by 2030, 90% by 2035, and 100% by 2040. Carbon-free resources include wind, solar, hydropower and nuclear generation. To provide flexibility, the law allows electric utilities to use RECs to offset carbon emissions and for the MPUC to consider whether a regulated utility's requirement to meet established standards should be delayed due to affordability or reliability impacts. We anticipate at least 80% of our Minnesota retail sales will be served with carbon-free generation by 2030, in compliance with Minnesota's clean energy requirements.
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 other emission reduction measures which may require future capital investments or ongoing operating and monitoring costs.
Financial Impacts
For the five-year period ended December 31, 2024, OTP invested approximately $4.8 million in environmental control equipment, including $1.7 million in 2024. Our capital budget for the next five years includes approximately $9.0 million of capital investments in environmental control equipment. The timing and amount of our expenditures may change as the regulatory environment changes.
Emerging Environmental Regulation
Regional Haze Rule (RHR). The Environmental Protection Agency (EPA) adopted the RHR 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 state implementation plans (SIPs) that work towards achieving natural visibility conditions by the year 2064; to set goals to ensure reasonable progress is being made; and to periodically evaluate whether those goals and progress are on track or whether additional emission reductions are necessary. The second RHR implementation period covers the years 2018-2028.
Coyote Station, OTP's jointly owned coal-fired power plant in North Dakota, is subject to assessment in the second implementation period under the North Dakota SIP. The North Dakota Department of Environmental Quality (NDDEQ) submitted its SIP to the EPA in August 2022. In its plan, the NDDEQ concluded it is not reasonable to require additional emission controls during this planning period.
On December 2, 2024, the EPA published its final ruling on North Dakota's SIP, approving certain aspects of the plan and disapproving other aspects of the plan. Regarding the partial disapproval, the EPA found that North Dakota failed to submit a long-
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term strategy that includes enforceable emissions limitations, compliance schedules, and other measures necessary to make reasonable progress on national visibility goals. Specific to Coyote Station, the EPA found that North Dakota relied on non-statutory visibility modeling to reject the installation of additional nitrogen oxides (NOx) and sulfur dioxide (SO2) emission controls.
Having disapproved, in part, the North Dakota SIP, the EPA now must promulgate a Federal Implementation Plan within two years from the issuance of its final decision. The Federal Implementation Plan may include emission controls required to satisfy the requirements of the RHR.
We cannot predict with certainty the final resolution of regional haze compliance in North Dakota and specifically the impact, if any, on the operations of Coyote Station. However, significant emission control investments could be required which may have a material impact on our operating results, financial condition and liquidity. Alternatively, such investments may prove to be uneconomic and result in the early closure, sale of or withdrawal from our interest in Coyote Station.
Clean Air Act. In May 2024, the EPA finalized new regulations under Section 111 of the Clean Air Act to regulate GHG emissions from existing and new fossil fuel-based power plants. The final rule establishes subcategories for new combustion turbines and existing coal-fired power plants to achieve certain CO2 emission reduction levels based on the respective subcategory. For existing coal-fired power plants, the applicable subcategory is based upon the date at which the plant will cease operations.
For existing coal-fired power plants anticipated to be operated after January 2039, the regulation set a Best System of Emission Reduction (BSER) based on 90% capture and sequestration of CO2 emissions with a compliance date of January 2032. For existing coal-fired power plants anticipated to be operated after January 2032 but plan to cease operations before January 2039, the regulation set a BSER of 40% co-firing with natural gas, which would result in a 16% reduction in CO2 emissions rate with a compliance date of January 2030. Coal-fired power plants with federally enforceable plans to cease operations by January 2032 are not subject to this regulation.
Several states and industry groups have filed lawsuits challenging the new regulation, arguing the EPA has overstepped its authority under the Clean Air Act.
We continue to review and evaluate the final regulations and the ongoing legal challenges. We cannot at this time conclude what the impact may be on our power plants and the potential impact to our operating results, financial condition and liquidity. However, significant emission control investments could be required, which may have a material impact on our operating results, financial condition and liquidity. Alternatively, such investments may prove to be uneconomic and result in the early closure, sale of or withdrawal from our interest in a coal-fired plant. Coyote Station and Big Stone Plant, our two co-owned coal-fired power plants, are within the scope of the regulations but our combustion turbines are not within the scope of the final regulation.
Coal Combustion Residual (CCR) Regulation. In May 2024, the EPA published a final rule amending CCR regulations, which introduce new requirements for the management of coal ash at active coal-fired power plants and inactive coal-fired power plants with a legacy surface impoundment. The regulations impose new requirements including groundwater monitoring, closure standards, post-closure care obligations and potential remediation activities. We anticipate we will incur costs related to coal ash removal and groundwater monitoring in the future as a result of the amended regulation; however, we continue to review and evaluate the overall impact this regulation may have on our business, including potential impacts to our operating results, financial condition and liquidity.
Mercury and Air Toxics Standards. In May 2024, the EPA published final regulations to strengthen and update Mercury and Air Toxics Standards for coal-fired power plants, tightening the emission standard for toxic metals and finalizing a reduction standard for mercury from existing lignite-fired sources. We continue to review and evaluate the overall impact this regulation may have on our business, including potential impacts to our operating results, financial condition and liquidity.
Climate Change and Greenhouse Gas Regulation
Global climate change presents a significant energy and environmental policy challenge. Combustion of fossil fuels for the generation of electricity is a considerable source of CO2 emissions, which is the primary GHG emitted by our utility operations. The federal government, many states and international organizations are pursuing climate policies to regulate GHG emissions as part of a broad-based effort to limit global warming.
The Minnesota Clean Energy Law, passed in 2023, requires electric utilities to generate or procure sufficient electricity from carbon-free resources to provide retail customers in Minnesota with at least the following percentages of carbon-free electric energy: 80% by 2030, 90% by 2035, and 100% by 2040.
The implementation of climate change programs, such as the Minnesota Clean Energy Law, regulations under the Clean Air Act and other existing or future federal or state regulations targeting GHG emissions, may have a significant impact on our utility business.
While the future financial impact of any current, proposed or pending 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
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adversely impact our future operating results, financial position and liquidity unless such costs could be recovered through related rates and/or future market prices for energy.
| MANUFACTURING | Contribution to Operating Revenues: 26% (2024), 30% (2023), 27% (2022) | ||||
Our Manufacturing businesses are engaged in the production of metal or plastics products sold to commercial customers. The following is a brief description of each of these businesses:
BTD Manufacturing, Inc. (BTD), with facilities in Detroit Lakes and Lakeville, Minnesota, Washington, Illinois and Dawsonville, Georgia, provides metal fabrication services for custom machine parts and metal components. BTD is a full-service contract metal fabricator with capabilities in metal stamping and fabrication, tool and die, machining, tube bending, welding, assembly and product painting.
T.O. Plastics, Inc. (T.O. Plastics), with facilities in Otsego and Clearwater, Minnesota, manufactures thermoformed plastics products, including its own line of horticulture containers and custom packaging products for the medical and industrial product markets.
CUSTOMERS
Our metal fabrication business primarily serves Midwestern and Southeastern U.S. original equipment manufacturers (OEM) in the recreational vehicle, lawn and garden, agricultural, construction, industrial, energy equipment and other end markets. Our customers include some of the largest recreational vehicle and equipment manufacturers based in the U.S.
Our plastic products business primarily serves U.S. customers in the horticulture, medical and life sciences, industrial, recreational and electronics industries. Most of our horticulture products are sold through distributors. Our customer packaging products are manufactured to customer specifications and sold directly to the end customer.
Although we sell our products to a large number of customers across a diverse group of end markets, two customers combined to account for approximately 36% of segment operating revenues in 2024.
The principal method of production distribution is by direct shipment to our customers through direct customer pick-up or common carrier ground transportation.
The following presents our revenue by end market for the years ended December 31, 2024 and 2023:
COMPETITIVE CONDITIONS
We compete in a highly fragmented market with competition from both domestic and international entities. Our competitors vary in size, ranging from small companies focused on certain end markets or geographical area, to large companies with broad manufacturing capabilities and domestic and international geographical reach. Competition can be geographically regionalized as customers procure products locally to manage cost and minimize logistical complexities. Certain competitors may have broader product lines, more manufacturing capacity and greater distribution capabilities than we do.
We believe the principal competitive factors in our Manufacturing segment are product performance, quality, price, technical innovation, cost effectiveness, customer service and breadth of product line. We intend to continue to compete based on high quality products, innovative production technologies, cost-effective manufacturing techniques, close customer relations and support, and increasing product offerings.
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In December 2024, we completed an expansion project at our Georgia location, which added approximately 162,000 square feet of owned manufacturing and warehouse space and will replace a warehouse facility that is currently being leased near the same location. This expansion provides additional manufacturing capacity in the southeastern U.S. to meet customer demand as their manufacturing base expands in the same region.
RESOURCE MATERIALS
We use raw materials in the products we manufacture, including, among others, steel, aluminum, and polystyrene and other plastics resins. Managing price volatility and ensuring raw material availability are important aspects of our business. We attempt to pass increases in the costs of these raw materials through to our customers. Increases in the costs of raw materials that cannot be passed on to customers could have a negative effect on profit margins. Additionally, a certain amount of residual material (scrap) is a by-product of the manufacturing and production processes. Declines in commodity prices for these scrap materials due to weakened demand or excess supply can negatively impact the profitability of our Manufacturing segment.
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: 35% (2024), 31% (2023), 35% (2022) | ||||
Our Plastics businesses produce PVC pipe at plants in North Dakota and Arizona. The following is a brief description of these businesses:
Northern Pipe Products, Inc. (Northern Pipe), located in Fargo, North Dakota, manufactures and sells PVC pipe for municipal water, rural water, wastewater, storm drainage systems and other uses in the northern, midwestern, south-central and western regions of the United States as well as central and western Canada.
Vinyltech Corporation (Vinyltech), located in Phoenix, Arizona, manufactures and sells PVC pipe for municipal water, wastewater, water reclamation systems and other uses in the western, northwest and south-central regions of the United States.
PVC pipe is manufactured through an extrusion process, during which PVC compound (a dry powder-like substance) is blended with other materials and 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. We produce pipe in a variety of diameters ranging from 3/4" to 24" and in varying lengths, generally from 10 feet to 20 feet.
CUSTOMERS
Our PVC pipe is used in municipal and wastewater systems, residential and commercial plumbing applications, and rural water systems.
Our pipe products are marketed through a combination of independent sales representatives, company salespersons and customer service representatives. Substantially all of our products are sold through distribution partners, which range from large, national distributors to smaller regional or local distributors. In 2024, two customers, both of which are distributors of PVC pipe, combined to account for 52% of segment operating revenues.
The principal method for distribution of our products is by common carrier ground transportation.
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The following presents our revenue by end market for the years ended December 31, 2024 and 2023:
COMPETITIVE CONDITIONS
Competition in the plastic pipe industry arises from other PVC pipe manufacturers 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, product availability, shipping costs and product performance.
Industry competition is characterized by a limited number of competitors, with the three largest competitors capturing a significant portion of the overall market. These competitors have a broader geographical reach, integration with PVC resin producers, greater manufacturing capacity and national relationships with key distribution partners. We compete on a regional basis, serving our core markets with strong customer service and high-quality products.
In addition to competition with other PVC pipe manufacturers, our PVC pipe competes with other products that serve the same end markets, including ductile iron, high-density polyethylene (HDPE), steel and concrete pipe products.
We will continue to compete based on our high level of service quality, including being a responsive and reliable partner to our customers, through maintaining product availability, by producing high-quality products and using cost-effective production techniques.
In December 2024, we completed an expansion project at our Arizona location, which added approximately 62,000 square feet of manufacturing, warehouse and office space, allowing for additional manufacturing capacity, including the ability to produce large diameter pipe to serve our customers in our regional market.
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 and in 2024 we utilized all four vendors to source our PVC resin. Our contractual arrangements to acquire resin generally include estimated annual order quantities, with no required minimum purchases, and include variable pricing based on market prices for resin. The supply of PVC resin may also be limited due to manufacturing capacity and the limited availability of raw material components, along with rail transportation disruptions from PVC resin plants to our facilities. Most U.S. resin production plants are located in the Gulf Coast region. These plants are subject to the risk of damage and production shutdowns because of exposure to hurricanes or other extreme weather events that occur in this part of the United States. The loss of a key vendor or any interruption or delay in the supply of PVC resin could disrupt the ability of our Plastics segment businesses to manufacture products, cause customers to cancel orders or result in increased expenses for obtaining PVC resin from alternative sources, if such sources were available. We believe we have good relationships with our key raw material vendors.
Due to the commodity nature of PVC resin and the dynamic supply and demand factors worldwide, historically the market for PVC resin has been cyclical and subject to significant fluctuations in price.
In addition to PVC resin, we use certain other materials, such as stabilizers, waxes, gaskets and lumber, in the process of manufacturing and shipping our PVC pipe products. We generally source these materials from a limited number of suppliers, and supply chain constraints or disruptions related to these materials could disrupt our ability to manufacture or ship products and could result in increased costs.
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SEASONALITY
Demand for our PVC pipe products can be impacted by seasonal weather differences, with generally lower sales volumes realized in the first quarter of the year when cold temperatures and frozen ground across the northern portion of our footprint can delay or prevent construction activity and consequently delay or prevent customer orders of PVC pipe.
ENVIRONMENTAL REGULATION
Our plastics businesses are subject to environmental, health and safety laws and regulations, including those governing discharges to air and water, the management and disposal of hazardous substances, the cleanup of contaminated sites and health and safety matters.
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| ITEM 1A. | RISK FACTORS | |||||||||||||
RISK FACTORS AND CAUTIONARY STATEMENTS
Our businesses are subject to various risks and uncertainties. Any of the risks described below or elsewhere in this report on Form 10-K or in our other SEC filings could materially adversely affect our business, operating results, financial condition and liquidity. Additional risks and uncertainties we are not presently aware of or that we currently consider immaterial may also affect our business, operating results, financial condition and liquidity.
OPERATIONAL RISKS
Our strategy includes large capital investments, which are subject to risks.
Our business strategy includes major capital investments at our operating companies. These capital projects are planned years in advance of their in-service dates and are subject to various risks including adverse changes in regulatory treatment or public policy; changes in commodity pricing or construction costs; delivery of critical materials; obtaining necessary permits and licenses; and other adverse conditions. Capital investments in our Electric segment require regulatory approval and are subject to the risks of not being granted timely approval or allowed to be fully recovered. In addition, our ability to construct and own utility assets may be impacted by regulatory requirements to competitively bid such investments, which could impact the amount and timing of our capital investments. A lack of direct ownership, or the inability to complete capital projects on budget and in a timely manner could impact our ability to achieve our strategic financial goals and could adversely impact our operating results and financial condition.
Weather impacts, including seasonal fluctuations, could adversely affect our operating results.
Our Electric segment business is seasonal, and weather patterns have had an impact on our financial performance in the past and may again in the future. Demand for electricity is normally greater in the winter and summer months. Unusually mild summers and winters could have an adverse effect on our financial condition and results of operations. Our Plastics segment businesses can be affected by seasonal weather prohibiting or delaying construction projects at any time of the year in any geography, but specifically times of the year when frozen ground and cold temperatures in many parts of the country can delay construction projects, all of which can result in reduced customer demand and could have an adverse effect on our financial condition, operating results and liquidity.
We are subject to physical and transition risks associated with climate change and extreme weather events.
Longer term shifts in climate patterns may impact our customers' demand for electricity, interrupt our business operations and damage our facilities; reduce the availability of natural resources, such as water; and cause disruptions in our supply chains.
Climate change may increase the frequency and severity of extreme weather events, such as prolonged periods of extreme cold or heat, and natural disasters, such as severe snow and ice storms, tornadoes, flooding and wildfires. These acute events could result in the interruption of our business operations and damage to our facilities. We may not have sufficient insurance coverage to avoid adverse impacts to our operating results or financial condition from damage to our facilities or an interruption in our business. An extreme weather event within our utility service area could directly affect our capital assets, causing disruption in service to customers, and result in reduced operating revenues and additional repair or replacement costs, due to downed wires and poles or damage to other operating equipment.
In the past, severe weather events in the Gulf Coast region of the U.S. have disrupted the supply of PVC resin, the primary material input of our Plastics segment businesses. As most U.S. PVC resin production plants are located in the Gulf Coast region, an area prone to seasonal hurricane activity and other extreme weather events, our access to PVC resin may be impacted by the volume and magnitude of hurricane and storm activity in this region, which could impact our Plastics segment businesses.
Increased risk of natural disasters, such as wildfires, could have financial consequences, including limiting our ability to secure sufficient insurance coverage, or lead to increased insurance cost. While we carry liability insurance, given an extreme event, if we were found to be liable for damages, amounts that exceed our coverage limit could negatively impact our financial condition, operating results and liquidity.
These risks may also negatively impact our credit ratings, which may limit our access to capital markets and increase our borrowing costs. In addition, to the extent investors view climate change, fossil fuel combustion and GHG emissions as a financial risk, our stock price or our ability to access capital markets on favorable terms and conditions could be adversely impacted.
We may experience transition risks in moving towards low carbon generation and manufacturing. For example, we may face challenges with the adoption of new technologies, meeting changing customer expectations, ensuring reliability of electric service, and committing to voluntary GHG emissions reduction goals, as well as complying with evolving local, state or federal regulatory requirements intended to reduce GHG emissions.
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Our operations are subject to environmental, health and safety laws and regulations.
We are subject to numerous federal, state and local environmental, health and safety laws and regulations governing, among other things, discharges to air and water, natural resources, hazardous waste and toxic substances, the cleanup of contaminated sites, and health and safety matters. Our failure to comply with applicable laws and regulations could result in civil or criminal fines or penalties, enforcement actions, and regulatory or judicial orders enjoining or curtailing operations or requiring corrective measures, which could materially and adversely affect our business. Compliance with these laws and regulations is a significant factor in our business. We have incurred and expect to continue to incur capital expenditures and operating costs to comply with applicable current and future laws and regulations.
Our businesses continue to be subject to additional and changing environmental, health and safety laws and regulations, and we could incur additional costs complying with requirements that are promulgated in the future. New laws or regulations or changes to existing laws and regulations in the future may result in disruptions to our business, changes in customer preferences or changes in customer demand, which could adversely impact our financial condition, operating results and liquidity.
Recently, various federal and state agencies have heightened their scrutiny of per- and polyfluoroalkyl substances (PFAS), which are manufactured chemicals used in a variety of consumer and industrial products. Regulators have recently proposed additional chemicals be designated as hazardous substances, including a proposal to designate perfluorooctanesulfonic acid and perfluorooctanoic acid, two of the most common PFAS chemicals, as hazardous substances, which could have wide-ranging impacts on companies across various industries, including ours. At this time, we cannot predict the outcome or the severity of the impact, if any, of future laws or regulations enacted to address PFAS.
Claims, litigation, government investigations and other proceedings may adversely affect our business, operating results and liquidity.
We are periodically subject to actual and threatened claims, litigation, investigations and other proceedings, including proceedings by governments and regulatory authorities, involving utilities regulation, competition and antitrust, product quality matters, and liability claims.
Any of these proceedings, including the currently ongoing proceedings related to our Plastics segment businesses, could have an adverse effect on our financial condition, operating results and liquidity. It is possible that a resolution of one or more proceedings, including as a result of a settlement, could involve damages, sanctions, consent decrees or orders requiring us to make substantial future payments, prevent us from offering certain products or services, require us to change our business practices in a manner materially adverse to our business, otherwise disrupt our business, divert management resources, damage our reputation or otherwise have a material effect on our operations. The outcomes of these matters are inherently unpredictable and subject to significant uncertainties, and we are unable to determine the likelihood of an outcome or estimate a range of reasonably possible losses, if any, arising from the proceedings at this time.
A cyber incident, security breach or system failure could adversely affect our business and operating results.
The operation of our business is dependent on the secure functioning of our computer hardware and software systems, as well as that of third-party service providers and vendors. Information systems, both ours and those of third parties, are vulnerable to security breaches by computer hackers and cyber terrorists, system failures, the negligent or intentional breach of established controls and procedures or mismanagement of confidential information by employees. Cyber-attacks or other security breaches may also be perpetrated through the use of artificial intelligence, which could introduce additional complexity to such an attack or breach. While we employ a defense-in-depth strategy and regularly conduct cybersecurity assessments, we cannot be certain our information security systems and protocols and those of our vendors and other third parties are sufficient to withstand a cyber-attack or other security breach.
A system failure could result in a disruption to our business including, but not limited to, the inability to produce products or serve our customers. A prolonged system failure could negatively impact our operating results. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage, and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to our reputation. For example, we may be subject to liability under various federal, state and international disclosure laws and data protection laws. These laws are subject to change and expansion and may require additional operational changes and costs to comply.
The misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant monetary damages, regulatory enforcement actions and breach notification and mitigation expenses, such as credit monitoring, and result in reputational damage affecting relations with shareholders, customers, regulators and others. In addition to property and casualty insurance, which may cover restoration of data, certain physical damage or third-party injuries, we have cybersecurity insurance related to a breach event. However, damage and claims arising from such incidents may not be covered or may exceed the amount of any available insurance.
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The loss of or significant reduction in revenue from any of our key customers could have an adverse effect on our operating results.
In 2024, a single customer provided more than 10% of our consolidated operating revenues, and each of our segments have customers which accounted for over 10% of the segment’s operating revenues. In 2024, two customers combined to account for 19% of Electric segment revenues, two customers combined to account for 36% of Manufacturing segment operating revenues and two customers combined to account for 52% of Plastics segment operating revenues, with one of those customers providing more than 10% of our consolidated operating revenues. The loss of any one of these customers or a significant decline in sales to these customers, would have a significant negative impact on the segment's financial condition and operating results, and could have a significant negative impact on the Company’s consolidated financial condition, operating results and liquidity.
The inability to attract and retain a qualified workforce could have an adverse effect on our operations.
The success of our business is heavily dependent on the leadership of our executive officers and key employees for implementation of our strategy. In addition, all of our businesses rely on a qualified workforce, including technical employees who possess certain specialized knowledge and skills. The inability to attract and retain a skilled and stable workforce at necessary staffing levels, whether due to decreases in hiring rates, increases in employee retirements, increases in terminations, or any combination thereof, may negatively affect our ability to service our customers, manufacture products or successfully manage our business and achieve our objectives.
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 indebtedness could also impact our operating results.
A decrease in our credit ratings could increase our borrowing costs and result in additional contractual costs.
We rely on our investment grade credit ratings to provide acceptable costs for accessing the capital markets. A downgrade of our credit ratings could result in higher borrowing costs thereby negatively impacting our operating results and limiting our ability to access capital markets, which may negatively impact our ability to implement our business plans. In addition, OTP is a party to contracts that require the posting of collateral or settlement of applicable contracts if credit ratings fall below certain levels, which may negatively impact our financial condition or liquidity.
Our pension and other postretirement benefit plans are subject to investment and interest rate risks.
The financial obligations and related costs of our pension and other postretirement benefit plans are affected by numerous factors. Assumptions related to future costs, investment returns, actuarial estimates and interest rates have a significant effect on our funding obligations and the cost recognized related to these plans. If our pension plan assets do not achieve our estimated long-term rate of return or if our other estimates prove to be inaccurate, our operating results, financial condition and liquidity may be adversely impacted. In addition, our funding requirements could be impacted by changes to the Pension Protection Act.
We rely on our subsidiaries to provide sufficient earnings and cash flows to allow us to meet our financial obligations and pay dividends to our shareholders.
OTC is a holding company with no significant operations of its own. The primary source of funds for payment of our financial obligations and dividends to our shareholders is from cash provided by our subsidiary companies. Our ability to meet our financial obligations and pay dividends on our common stock principally depends on the earnings, cash flows, capital requirements and general financial positions of our subsidiary companies. In addition, OTP is subject to federal and state regulations which may restrict its ability to pay dividends. Finally, we are also reliant on our subsidiary companies to maintain compliance with financial covenants under our various short- and long-term debt agreements. Our debt agreements include restrictions on the payment of cash dividends upon an event of default.
Changes in tax laws could materially affect our financial condition and operating results.
Our provision for income taxes and tax obligations are impacted by various tax laws and regulations, including the availability of various tax credits, IRS tax policies such as tax normalization and, at times, the ability to carryforward net operating losses and tax credits. Changes in tax laws, regulations and interpretations could have an adverse effect on our financial condition and operating results. Tax law changes that reduce or eliminate production or investment tax credits (ITCs), or the ability to transfer or sell these credits, or a failure to meet the compliance requirements to receive these credits, may impact the economics of constructing certain electric generation resources, which may impact our planned investments, and could adversely affect our financial condition and operating results.
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ELECTRIC SEGMENT RISKS
Our utility business is significantly impacted by government legislation and regulation.
OTP is subject to federal and state legislation and comprehensive regulation by federal and state regulatory agencies, including the public utility commissions in each of the three states in which OTP operates, and by the FERC.
Our financial condition, operating results and liquidity are significantly impacted by and dependent upon our ability to recover the costs associated with providing utility service and earn a return on our utility capital investments. There is no assurance that each state utility commission will judge our utility costs to have been prudently incurred or that rates will produce full recovery of such costs. In addition, changes in the federal or state regulatory framework could impair our ability to recover utility costs historically collected from our customers. Diverging public policy priorities across the jurisdictions we serve and a lack of inter-jurisdictional consensus may impact our ability to recover the cost of and return on our capital investments and our operating costs; it may impact our future capital investment opportunities; and may result in inefficiencies which could negatively impact our financial position, operating results and liquidity.
In addition to the recovery of our utility costs, our profitability is impacted by our authorized ROE, which can be impacted by macroeconomic factors such as interest rates. There can be no assurance that each state utility commission or the FERC will authorize a rate of return which allows us to achieve our financial goals. An adverse decision by one or more regulatory authorities or any prolonged delay in rendering a decision in a rate or other proceeding could adversely impact our financial condition, operating results and liquidity.
Inflationary cost pressures have increased the cost of constructing our utility assets and operating our utility business. There can be no assurance that our state regulatory commissions will authorize recovery of rising costs. Regulatory commissions may also limit future capital investments, or the rate of return allowed on such investments in response to inflationary cost pressures and customer bill impacts. Such limitations could negatively impact our financial position, operating results and liquidity.
We may be unable to fully recover costs of our co-owned coal-fired generating facilities.
Changes in regulatory, operational or economic factors could result in the early closure or sale of or withdrawal from our interest in a coal-fired generating facility. In the event of an early closure, a significant asset impairment charge could be required, and we would be obligated to pay for our share of the costs of closure of the generating facility. In the event of a sale of our interest in a generating facility, we may be unable to negotiate the sale on favorable terms, which could result in the recognition of a loss on the sale. There can be no assurance that we would be authorized by any of our state utility commissions to recover any costs or losses associated with the early closure or sale of our interest in a generating facility.
Our IRP, approved in Minnesota by the MPUC in May 2024, directs OTP to commence activities to no longer serve Minnesota customers with capacity or energy from Coyote Station as early as 2029. The discontinuation of service to Minnesota customers from Coyote Station could result in stranded costs, which may significantly impact our operating results, financial condition and liquidity.
Environmental regulation could require us to incur substantial capital expenditures, increased operating costs or make it no longer economically viable to operate some of our facilities.
We are subject to federal, state and local environmental laws and regulations relating to air quality, water quality, waste management, natural resources and health safety. These laws and regulations regulate the modification and operation of existing facilities, the construction and operation of new facilities and the proper storage, handling, cleanup and disposal of hazardous waste and toxic substances. Compliance with these legal requirements may require us to commit significant resources and funds toward environmental monitoring, installation and operation of pollution control equipment, payment of emission fees and securing environmental permits. Obtaining environmental permits can entail significant expense and cause substantial construction delays. Failure to comply with environmental laws and regulations, even if caused by factors beyond our control, may result in civil or criminal liabilities, penalties and fines.
Coyote Station, one of OTP's jointly owned coal-fired power plants, is subject to assessment under the second planning period of the RHR as part of the state of North Dakota's RHR SIP. In December 2024, the EPA partially disapproved the North Dakota SIP related to Coyote Station and now must promulgate a Federal Implementation Plan. The federal plan may include emission controls required to satisfy the requirements of the RHR. We cannot predict with certainty the final resolution of regional haze compliance in North Dakota and specifically the impact, if any, on the operations of Coyote Station. However, significant emission control investments could be required which may have a material impact on our operating results, financial condition and liquidity. Alternatively, such investments may prove to be uneconomic and result in the early closure, sale of, or withdrawal from, our interest in Coyote Station.
Existing environmental laws or regulations may be revised, and new laws or regulations may be adopted or become applicable to us. The multiple jurisdictions that govern our electric utility business may not agree as to the appropriate resource mix, which may lead to costs incurred to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets. Revised
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or additional regulations which result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material effect on our financial condition, operating results and liquidity, making the operation of some of our facilities no longer economically viable.
Actions to address climate change and greenhouse gas emissions could materially impact us.
Current and future federal, state, regional and international legislation and regulations to address global climate change and reduce GHG emissions, including measures such as mandated levels of renewable generation, mandatory reductions in CO2 emission levels, taxes on CO2 emissions, or cap-and-trade regimes, could require us to incur significant costs, which could negatively impact our financial condition, operating results and liquidity if such costs cannot be recovered through rates granted by rate-making authorities or through increased market prices for electricity.
In May 2024, the EPA finalized new regulations under Section 111 of the Clean Air Act to regulate GHG emissions from existing and new fossil fuel-based power plants. The new regulations require existing coal-fired power plants to achieve certain CO2 emissions reduction levels, with the amount of reduction dependent upon the remaining operating life of the facility. The new regulation has the potential to materially impact the operations of our coal-fired power plants, which could have a material impact on our operating results, financial condition and liquidity.
In addition to complying with legislation and regulation, we could be subject to litigation related to climate change. If we were subjected to such litigation, the costs of such litigation could be significant and an adverse outcome could require substantial capital expenditures, changes in operations and possible payment of penalties or damages, which could affect our financial condition, operating results and liquidity if the costs are not recoverable in rates or covered by insurance.
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.
Violations of extensive legal and regulatory compliance requirements could have a negative impact on our business and results of operations.
We are subject to an extensive legal and regulatory framework imposed under federal and state laws and regulatory agencies, including the FERC and the North American Electric Reliability Corporation (NERC). We could be subject to potential financial penalties for compliance violations. Our transmission systems and electric generation facilities are subject to the NERC mandatory reliability standards, including cybersecurity standards. If a serious reliability incident were to occur, it could have a material effect on our operations or financial results. Some states have the authority to impose substantial penalties in the event of non-compliance. We attempt to mitigate the risk of regulatory penalties through formal training. However, there is no guarantee our compliance program will be sufficient to ensure against violations.
These laws and regulations significantly influence our operations and may affect our ability to recover costs from our customers. We are required to have numerous permits, licenses, approvals and certificates from the agencies and other organizations that regulate our business. We believe we have obtained the necessary approvals for our existing operations and that our business is conducted in accordance with applicable laws and regulatory requirements; however, we are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies and other organizations. Changes in regulations or the imposition of additional regulations could have a material adverse impact on our financial condition, operating results and liquidity.
Our generation, transmission and distribution facilities could be vulnerable to cyber and physical attack.
OTP owns electric transmission, distribution and generation facilities subject to mandatory and enforceable standards advanced by the NERC. These bulk electric system facilities provide the framework for the electrical infrastructure of OTP’s service territory and interconnected systems, the operation of which is dependent on information technology systems. Further, the information systems that operate OTP’s electric system are interconnected to external networks. Parties that wish to disrupt the U.S. bulk power system or OTP’s operations could view OTP’s computer systems, software or networks as attractive targets for cyber-attack.
In addition, OTP’s generation and transmission facilities are spread throughout a large service territory. These facilities could be subject to physical attack or vandalism that could disrupt OTP’s operations or conceivably the regional or U.S. bulk power system.
OTP is subject to mandatory cybersecurity and physical security regulatory requirements. OTP implements the NERC standards for operating its transmission and generation assets and remains abreast of best practices within the business and the utility industry to
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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 transmission, distribution and generation facilities. However, all these measures and technology may not adequately prevent security breaches, ransomware attacks or other cyber-attacks, or enable us to recover effectively from such a breach or attack. Any significant interruption or failure of our information systems or any significant breach of security due to cyber-attacks, hacking or internal security breaches or physical attack of our generation or transmission facilities could adversely affect our business and our financial condition, operating results and liquidity.
Our generation, transmission and distribution facilities are subject to operational risks, which include circumstances that could result in injuries, loss of life, property damage and fires.
The operation of our generation, transmission and distribution facilities involves many risks including equipment failures, accidents and workforce safety matters, environmental damage, property damage, operator error and the occurrence of catastrophic events such as fires, explosions and floods. Diminished availability or performance of those facilities could result in facility shutdowns, reduced customer satisfaction, reputational harm and regulatory inquiries and fines.
Accidents, fires, explosions, catastrophic failures, general system damage or dysfunction, intentional acts of destruction and other unplanned events related to our infrastructure would increase repair costs and may expose us to liability for personal injury, loss of life and property damage. Fires alleged to have been caused by our transmission, distribution or generation infrastructure, or that allegedly result from our contractors’ operating or maintenance practices, could also expose us to claims for fire suppression and clean-up costs, evacuation costs, fines and penalties, and liability for economic damages, personal injury, loss of life, property damage and environmental pollution, whether based on claims of negligence, trespass or otherwise. We maintain insurance coverage for such operating and event risks, but insurance coverage is subject to the terms and limitations of the available policies and may not be sufficient in amount to cover our ultimate liability. We may be unable to fully recover costs in excess of insurance through customer rates or regulatory mechanisms. If the amount of insurance is insufficient or otherwise unavailable, and if we are unable to fully recover in rates the costs of uninsured losses, our financial condition, operating results and liquidity could be materially affected.
Joint ownership of coal-fired generation facilities could impact our ability to manage changing regulations and economic conditions.
We own our coal-fired generation facilities jointly with other co-owners with varying ownership interests in such facilities. Our ability to make determinations to best navigate changing environmental regulations and economic conditions may be impacted by our rights and obligations under the co-ownership and related agreements, and our ability to reconcile a divergence in the interests of OTP and the co-owners of these generation facilities. Such a divergence could impair our ability to effectively manage these changing conditions to meet our strategic objectives, and could adversely impact our financial condition, operating results and liquidity.
We are subject to risks associated with energy and capacity markets.
Our electric business is subject to the risks associated with energy and capacity markets, including changes in market supply, energy and capacity prices. If we need to procure market energy and are faced with shortages in market supply, we may be unable to fulfill our contractual obligations to our retail, wholesale and other customers at previously anticipated costs. This could force us to obtain alternative energy or fuel supplies at higher costs or suffer increased liabilities for unfulfilled contractual obligations. Changes in our own generation capacity or market capacity, including from changes in capacity accreditation, could lead to increased capacity prices. Significantly higher than expected energy or capacity costs could negatively affect our financial condition, operating results and liquidity.
We are subject to risks associated with the procurement and transportation of fuel to our coal and natural gas-powered generation facilities.
We rely on a limited number of suppliers to provide coal and a limited number of service providers to transport coal and natural gas to our facilities. A counterparty's failure to perform their obligations may arise due to liquidity challenges or insolvency, operational deficiencies or other circumstances such as severe weather or natural disasters and could impact our ability to provide service to our customers or require us to seek alternative sources for these products and services, if available. A prolonged failure to perform by one or more of our current suppliers or service providers could lead to increased costs or other consequences, which could negatively impact our financial condition, operating results and liquidity.
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MANUFACTURING SEGMENT RISKS
We are impacted by our customers' strategies, operational decisions and conditions in the end markets they serve.
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, industrial, energy and horticulture. Factors affecting any of these industries in general could adversely affect our operating results, as growth in our operating revenues is largely dependent on the growth of our customers’ businesses in their respective industries. These factors include:
•our customers’ failure to successfully market their products, gain or retain widespread commercial acceptance of their products or compete effectively in their industries;
•loss of market share for our customers’ products, which may lead our customers to reduce or discontinue purchasing our products and components and to reduce prices, thereby exerting pricing pressure on us;
•economic conditions in the markets in which our customers operate, the United States in particular, including recessionary periods such as a global economic downturn;
•our customers’ decisions to bring the production of components in-house that have traditionally been outsourced to us; and
•seasonality of demand for our customers’ products, which may cause our manufacturing capacity to be underutilized for periods of time;
•product design changes or manufacturing process changes that may reduce or eliminate demand for the components we supply.
We expect future sales will continue to depend on the success of our customers. If economic conditions or demand for our customers’ products deteriorates, we may experience a material adverse effect on our financial condition, operating results and liquidity.
The price and availability of raw materials could adversely impact our operating results.
The companies in our Manufacturing segment use a variety of raw materials in the products they manufacture including, among others, steel, aluminum, and polystyrene and other plastics resins. The price and availability of the raw materials used in our manufacturing processes are based on global supply and demand conditions, which can create volatile pricing and supply disruptions as conditions change. Federal trade policies, including imposed tariffs, can also impact prices for these raw materials. If we are unable to pass cost increases through to our customers or are unable to procure adequate or timely raw material inputs for use in our manufacturing processes, our financial condition, operating results and liquidity could be negatively impacted.
Additionally, a certain amount of residual material (scrap) is a by-product of the manufacturing and production processes used by our manufacturing companies. Declines in commodity prices for these scrap materials due to weakened demand or excess supply can negatively impact the profitability of our manufacturing companies as it reduces their ability to mitigate the cost associated with excess material.
Competition from domestic and foreign manufacturers could affect the revenues and earnings of our manufacturing businesses.
Our manufacturing businesses are subject to intense competition from domestic and foreign manufacturers, many of whom have broader product lines, greater distribution capabilities, greater capital resources, larger marketing, research and development personnel and facilities, and other capabilities. Our ability to compete on product performance, competitive pricing, technological innovation and customer service is critical to our ongoing success. If we are unable to compete in these and potentially other areas, our business and financial condition, operating results and liquidity could be adversely impacted.
Our business may be adversely affected if we are not able to maintain our manufacturing, engineering and technological expertise.
The markets for our manufacturing businesses are characterized by changing technology and evolving process development. The continued success of our businesses will depend on our ability to:
•maintain technological leadership in our industry;
•implement new and expand on current robotics, automation and tooling technologies; and
•anticipate or respond to changes in manufacturing processes in a cost-effective and timely manner.
We may be unable to develop the capabilities required by our customers in the future. The emergence of new technologies, industry standards or customer requirements may render our equipment, inventory or processes obsolete or noncompetitive. We may be required to acquire new technologies and equipment to remain competitive. The acquisition and implementation of new technologies and equipment may require us to incur significant expense and capital investment, which could reduce our margins and affect our operating results. Failure to anticipate and adapt to customers’ changing technological needs and requirements and to
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maintain manufacturing, engineering and technological expertise may have material adverse effects on our financial condition, operating results and liquidity.
PLASTICS SEGMENT RISKS
External factors beyond our control could cause fluctuations in demand for and pricing of our PVC pipe products.
Our PVC pipe products, sold through distributors and wholesalers, are primarily used in municipal and rural water projects, wastewater projects, storm drainage systems and reclamation systems. External factors beyond our control can cause volatility in demand for our products and sales prices impacting our operating margins. These factors can magnify the impact of economic cycles on our business and results of operations. Examples of external factors include:
•general economic conditions including housing and construction markets which can be cyclical;
•increases in interest rates;
•severe weather and natural disasters;
•governmental regulation in the United States; and
•funding shortages for municipal water and wastewater projects.
Sales prices for PVC pipe began to significantly increase in 2021, reaching a peak level in mid-2022. Pipe prices have since retreated from the high point but remain elevated compared to historic levels. Elevated pipe prices led to a significant expansion in our operating margins and cash generation. We expect sales prices for PVC pipe to continue to decline, which will cause a decline in operating margins and cash generation prospectively. The pace and magnitude of the decline in product pricing could materially impact our operating results and liquidity.
Changes in PVC resin prices could negatively affect our plastics business.
The cost of PVC resin is based on global supply and demand conditions, which can create volatile pricing. Changes in PVC resin cost prices can negatively affect PVC pipe prices and profit margins on PVC pipe sales.
Our plastics operations are highly dependent on a limited number of vendors and a limited supply of PVC resin and other materials.
We rely on a limited number of vendors to supply the PVC resin used in our plastics businesses. In 2024, we sourced all of our PVC resin needs from four vendors. In addition, the supply of PVC resin may be limited primarily due to manufacturing capacity and the limited availability of raw material components. Most U.S. resin production plants are located in the Gulf Coast region. This could increase the risk of a shortage of resin in the event of a hurricane, other extreme weather events and other natural disasters in that region. The loss of a key vendor or any interruption or delay in the availability or supply of PVC resin could disrupt our ability to deliver our plastic products, cause customers to cancel orders or require us to incur additional expenses to obtain PVC resin from alternative sources, if such sources were available.
Although PVC resin is the most significant raw material input in our PVC pipe manufacturing process, we also use certain other materials, such as stabilizers, gaskets, lumber, banding and others in the process of manufacturing and shipping our PVC pipe products. We generally source these materials from a limited number of suppliers and any significant supply chain constraints or disruptions related to these materials could also disrupt our ability to manufacture or ship products and could result in increased costs.
We compete against other manufacturers of PVC pipe and manufacturers of alternative products.
Competition in the plastic pipe industry arises from other PVC pipe manufacturers and the fungible nature of the product. Certain of the companies we compete with have a broader geographical reach, integration with PVC resin producers, greater manufacturing capacity and national relationships with key distribution partners. In addition to competing with other plastic pipe manufacturers, our products also complete against similar products serving the same end markets, including ductile iron, HDPE, steel and concrete pipe. Our inability to compete effectively on product price, customer service and product performance may adversely affect the financial performance of our plastics businesses.
GENERAL RISK FACTORS
Changes in economic conditions and economic policies could negatively impact our businesses.
Our businesses are affected by local, national and worldwide economic conditions. Economic recessions, inflation, changes in commodity prices, changes in interest rates and tightening of credit in financial markets could adversely affect our operating results, financial condition and liquidity. In addition, changes in government policies, including trade regulations and tariffs, could impact our businesses, including increasing our costs of materials, negatively impacting our supply chain, reducing sales volumes of our products or services, or disrupting the competitive environment in which we operate. A broad increase in tariffs may also lead to elevated inflation and increased interest rates, which may negatively impact national economic conditions and impact our operating results, financial condition and liquidity.
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If we are unable to achieve the organic growth we expect, our financial performance may be adversely affected.
We expect much of our growth in the next few years will come from major capital investments at existing companies. To achieve the organic growth we expect, we must have access to the capital markets, be successful with capital expansion programs related to organic growth, develop new products and services, expand our markets and increase efficiencies in our businesses. Competitive and economic factors could adversely affect our ability to do this. If we are unable to achieve and sustain consistent organic growth, we will be less likely to meet our earnings growth targets, which may adversely affect the market price of our common shares.
The effects of a major public health crisis, such as an epidemic or pandemic, and measures taken to reduce and slow the spread of the disease could adversely impact our business.
A future widespread outbreak of an infectious disease, which affects a large percentage of the population regionally, nationally or globally could impact our business operations, including our employees, customers, construction contractors, suppliers and vendors, and could impact our operating results, financial condition and liquidity.
| ITEM 1B. | UNRESOLVED STAFF COMMENTS | ||||||||||
None.
| ITEM 1C. | CYBERSECURITY | ||||||||||
CYBERSECURITY RISK
The operation of our businesses is dependent on the secure functioning of our computer infrastructure and digital information 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 service providers to electronically process certain of our business transactions and perform certain cyber-related functions, such as system monitoring and critical infrastructure protection and maintenance. The confidentiality, integrity and availability of information systems, both ours and those of our third-party service providers, 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 other business partners. As part of our utility operations, we own electric generation, transmission and distribution facilities that are part of an interconnected regional grid, the operation of which is dependent on information technology systems. Parties who wish to disrupt the U.S. bulk power system or our utility operations could view our computer systems, software or networks as attractive targets for cyber-attack. Although we have not historically experienced material cyber incidents, we and other utilities are subject to cyber-attacks of increasing frequency and sophistication, and any significant interruption or failure of our information systems or any significant breach of security due to cyber-attacks, hacking or internal security breaches, could adversely affect our business and our financial condition, operating results and liquidity.
RISK MANAGEMENT AND STRATEGY
Our cybersecurity policies and practices, which are based on the Center for Information Security (CIS) Critical Security Controls, are governed by our information and cybersecurity governance program. The CIS Critical Security Controls are a set of 18 cybersecurity-related controls which aid companies in designing an effective control environment and are viewed as best practices by organizations worldwide. A significant number of our cybersecurity policies and practices associated with our electric utility operations are also subject to regulation by multiple governmental and other agencies.
Our information and cybersecurity governance program is the foundation of our cybersecurity risk management strategy. The program includes policies which authorize and guide the development of procedures, standards and guidelines for personnel activities, incident prevention and reporting, and compliance monitoring. Cybersecurity policies, procedures and controls are reviewed and approved by our Information and Cybersecurity Program (ICSP) group annually, with amendments made as deemed necessary for any updates for regulatory compliance and best practices, legal privacy protection and information protection, or to reflect current technology or new methods for ensuring secure business procedures.
We perform a corporate risk assessment annually, which includes specific consideration and assessment of cybersecurity risk. As part of our risk assessment process, we incorporate results from procedures performed by third-party consultants. We utilize third-party consultants to perform penetration and vulnerability testing and monitoring, as well as overall cybersecurity control testing. Potential risks associated with the use of third-party service providers are monitored and managed through an established service provider management policy. Service providers must meet certain security requirements such as security incident or data breach notification and response protocols, data encryption requirements and data disposal commitments.
In managing cybersecurity risk, we employ a defense-in-depth strategy and regularly monitor our cyber environment for potential new threats. Our strategy includes employee training and awareness on cybersecurity risks and related best practices, required
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password complexity, the use of multi-factor authentication, information security protocols, anti-virus and anti-ransomware software, a patch management program, the execution of tabletop exercises on a periodic basis, established policies and protocols for cyber incident response planning and reporting, and ongoing internal cybersecurity testing.
GOVERNANCE
At the management level, our cyber program is managed by our ICSP group. The ICSP group consists of Information Technology (IT) managers, IT security subject matter experts, and internal audit personnel and is led by our Vice President of IT who has more than 25 years of experience in IT, enterprise security and cyber risk management, a Bachelor's degree of Science, CIS, Information Technology and Master's of Business, Information Systems, and holds Certified Information Systems Security Professional, Certified Information Security Manager and Certified Data Privacy Solution Engineer designations. The ICSP group is in charge of developing, maintaining and measuring compliance with the information and cybersecurity governance program, as well as monitoring cyber incidents and implementing mitigation measures as part of an evolving, dynamic external environment. Our approach to cybersecurity incident reporting and response planning is governed by our incident response plans established for each of our business units. The plans outline the processes related to detecting, assessing, investigating, mitigating and remediating cyber incidents, as well the communication and reporting plan and the required personnel to be included in the process and communications.
Our cybersecurity risk management is integrated into our overall risk management system through our internal business risk management process. Our business risk management group works closely with our ICSP group to regularly assess and identify possible material risks from cybersecurity threats, including but not limited to, financial, operations, reputational and regulatory impact to the Company, as well as impacts on our employees and customers. Their risk assessment results are reported to our Executive Risk Committee on a quarterly basis. The Executive Risk Committee, which is comprised of our executive officers, meets quarterly to identify and assess short-, medium- and long-term risks, and to ensure adequate mitigation strategies are implemented. During these meetings, the Executive Risk Committee reviews significant and emerging risks, including cybersecurity risks, and assesses the Company’s plans to mitigate or otherwise manage and monitor those risks.
Our Board of Directors provides oversight of our cybersecurity program through quarterly and annual risk reviews and cybersecurity reporting. On a quarterly basis, cybersecurity risk and mitigation strategies are reviewed as part of our business risk management group's reporting to the Board of Directors, which includes the reporting of significant business risks, including cybersecurity mitigation strategies employed to manage these risks and a review of any emerging risks. At least annually, our Vice President of IT provides an overview of our cybersecurity program to the Board of Directors, including a review of key strategies, emerging risks and a summary of key performance indicators. In addition, annually the Board of Directors reviews the results of our penetration and vulnerability testing.
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| ITEM 2. | PROPERTIES | |||||||||||||
The following provides a summary of our properties which are material to our operations, by segment, as of December 31, 2024.
ELECTRIC SEGMENT
The following reflects our wholly or jointly owned material electric generation facilities as of December 31, 2024:
| Description | Location | Year Placed in Service | Fuel Type | Capacity - kW (Nameplate Rating) | ||||||||||
Big Stone Plant(1) | Big Stone City, SD | 1975 | Subbituminous Coal | 223,146 | ||||||||||
Coyote Station(2) | Beulah, ND | 1981 | Lignite Coal | 144,900 | ||||||||||
| Jamestown Combustion Turbines | Jamestown, ND | 1975 | Fuel Oil | 48,108 | ||||||||||
| Lake Preston Combustion Turbine | Lake Preston, SD | 1978 | Fuel Oil | 24,100 | ||||||||||
| Solway Combustion Turbine | Solway, MN | 2003 | Natural Gas/Fuel Oil | 44,500 | ||||||||||
| Astoria Station | Astoria, SD | 2021 | Natural Gas | 245,000 | ||||||||||
| Langdon Wind Energy Center | Cavalier County, ND | 2007 | Wind | 40,500 | ||||||||||
| Ashtabula Wind Energy Center | Barnes County, ND | 2008 | Wind | 48,000 | ||||||||||
| Luverne Wind Energy Center | Griggs and Steele Counties, ND | 2009 | Wind | 49,500 | ||||||||||
| Merricourt Wind Energy Center | McIntosh and Dickey Counties, ND | 2020 | Wind | 150,000 | ||||||||||
Ashtabula III Wind Energy Center(3) | Barnes County, ND | 2023 | Wind | 62,400 | ||||||||||
| Hoot Lake Solar | Otter Tail County, MN | 2023 | Solar | 49,900 | ||||||||||
(1) OTP holds a 53.9% joint ownership interest in this jointly owned facility. The nameplate capacity indicated reflects OTP's ownership percentage. | ||||||||||||||
(2) OTP holds a 35.0% joint ownership interest in this jointly owned facility. The nameplate capacity indicated reflects OTP's ownership percentage. | ||||||||||||||
(3) Originally placed in service in 2010 and owned by an unrelated third party. OTP acquired this facility in 2023. | ||||||||||||||
In addition to our generation facilities, we wholly or jointly own transmission and distribution lines as of December 31, 2024 as follows:
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MANUFACTURING AND PLASTICS SEGMENTS
The following reflects the properties of our Manufacturing and Plastic segments as of December 31, 2024 which are significant to our operations:
| Segment/Location | Owned/Leased | Facility Type/Use | Approximate Square Feet | ||||||||
| Manufacturing Segment | |||||||||||
| Otsego, MN | Leased | Manufacturing/Warehouse | 86,000 | ||||||||
| Clearwater, MN | Owned | Office/Manufacturing/Warehouse | 204,000 | ||||||||
| Washington, IL | Leased | Office/Manufacturing/Warehouse | 218,000 | ||||||||
Sauk Rapids, MN | Leased | Warehouse | 278,000 | ||||||||
| Dawsonville, GA | Owned | Office/Manufacturing/Warehouse | 334,000 | ||||||||
| Detroit Lakes, MN | Owned | Office/Manufacturing/Warehouse | 354,000 | ||||||||
| Lakeville, MN | Leased | Office/Manufacturing/Warehouse | 413,000 | ||||||||
| Plastics Segment | |||||||||||
| Fargo, ND | Owned | Office/Manufacturing/Warehouse | 122,000 | ||||||||
| Phoenix, AZ | Owned | Office/Manufacturing/Warehouse | 149,000 | ||||||||
We believe the facilities described above are adequate for our present business.
| ITEM 3. | LEGAL PROCEEDINGS | ||||||||||
Several class action complaints have been filed against certain PVC pipe manufacturers, including OTC, alleging, among other things, that the defendants conspired to fix, raise, maintain, and stabilize the price of PVC municipal water and electrical conduit pipe in violation of United States antitrust laws. See Note 14, Commitments and Contingencies, to the consolidated financial statements, which information is incorporated herein by reference, for further discussion of this matter.
| 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 our 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 (60) | 04/13/15 | President and Chief Executive Officer | ||||||
| Todd R. Wahlund (54) | 01/01/24 | Vice President, Chief Financial Officer | ||||||
| Timothy J. Rogelstad (58) | 04/14/14 | Senior Vice President, Electric Platform | ||||||
| John S. Abbott (66) | 02/11/15 | Senior Vice President, Manufacturing Platform | ||||||
| Jennifer O. Smestad (54) | 01/01/18 | Vice President, General Counsel and Corporate Secretary | ||||||
Chuck MacFarlane has served as the Company’s President and Chief Executive Officer and as a member of the Company’s Board of Directors since April 13, 2015.
Todd Wahlund has served as Chief Financial Officer and Vice President since January 1, 2024, and previously served as Chief Financial Officer and Vice President, Finance for OTP from May 1, 2018 to December 31, 2023.
Timothy Rogelstad has served as President of OTP and Senior Vice President, Electric Platform of the Company since April 14, 2014.
John Abbott has served as Senior Vice President, Manufacturing Platform since February 11, 2015.
Jennifer Smestad has served as Vice President, General Counsel and Corporate Secretary of the Company since January 1, 2018. Ms. Smestad has also served as General Counsel for OTP since March 1, 2013.
The term of office for each of the executive officers is one year and any executive officer elected may be removed by the vote of the board of directors at any time during the term. There are no family relationships between any of the executive officers or directors.
| ITEM 4. | MINE SAFETY DISCLOSURES | ||||||||||
Not Applicable.
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PART II
| 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, 2024, there were 10,245 holders of record of our common stock.
We do not have a publicly announced stock repurchase program and we did not repurchase any equity securities during the quarter ended December 31, 2024.
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, 2019, and reinvestment of all dividends).
| 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | ||||||||||||||||||||||||||||||
| OTTR | $ | 100.00 | $ | 85.52 | $ | 147.06 | $ | 125.37 | $ | 185.62 | $ | 166.48 | |||||||||||||||||||||||
| EEI | $ | 100.00 | $ | 98.84 | $ | 115.76 | $ | 117.09 | $ | 106.90 | $ | 127.32 | |||||||||||||||||||||||
| Nasdaq | $ | 100.00 | $ | 121.27 | $ | 152.67 | $ | 122.55 | $ | 154.93 | $ | 192.86 | |||||||||||||||||||||||
| ITEM 6. | [RESERVED] | ||||
| 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.
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2024 FINANCIAL RESULTS
In 2024, our diversified business model generated record financial results, producing net income of $301.7 million, or $7.17 per diluted share, an increase of 3% from $294.2 million, or $7.00 per diluted share, in 2023. Our financial results for the year were driven by earnings growth in our Electric and Plastics segments, partially offset by a decline in our Manufacturing segment earnings. In 2024, we paid an annual dividend of $1.87 per share, or $78.3 million, completing our 86th consecutive year of dividend payments to our shareholders.
Our Electric segment produced earnings growth of 8% in 2024, from $84.4 million in 2023 to $91.0 million in 2024, primarily due to increased retail revenue resulting from an interim rate increase in North Dakota and increased rider revenue, partially offset by the investment and financing costs associated with our rate base investments, resulting in increased depreciation and interest expense compared to the prior year.
Our Manufacturing segment earnings decreased 36% in 2024, from $21.5 million in 2023 to $13.7 million in 2024, primarily due to soft end market demand, which resulted in lower sales volumes and a decrease in gross profit margins in our plastics thermoforming business, partially offset by reduced general and administrative expenses. Decreased profit margins were primarily due to reduced leveraging of fixed manufacturing costs resulting from decreased production and sales volumes.
Our Plastics segment produced earnings growth of 7%, from $187.7 million in 2023 to $200.7 million in 2024, primarily due to the impact of increased sales volumes, driven by strong customer and end market demand. Increased operating revenues, driven by increased sales volumes, were partially offset by a decrease in gross profit margins. Gross profit margins decreased primarily due to decreases in sales prices, which outpaced decreases in the cost of PVC resin and other input materials.
Our earnings mix in 2024 was 30% from our Electric segment and 70% from the combination of our Manufacturing and Plastics segments including unallocated corporate costs. Since 2021, our earnings mix has diverged from our long-term target of 65% from our Electric segment and 35% from our Manufacturing Platform primarily due to market conditions within the PVC pipe industry. These conditions have led to significant revenue, earnings and cash flow growth in our Plastics segment. Currently, we expect these industry conditions to gradually normalize through 2027. As they do, we expect earnings and cash flow generation within our Plastics segment to moderate from current levels and our earnings mix to return to our long-term targeted mix.
PVC PIPE MARKET CONDITIONS
Extraordinary supply and demand conditions in the PVC industry beginning in 2021 have led to a significant expansion in operating margins and elevated earnings in our Plastics segment over the past four years. Periodic disruptions in the supply of PVC resin, the primary material input used in the manufacturing of PVC pipe, coupled with robust demand for resin, led to a significant increase in the cost of resin beginning in 2021. During this time, robust end market demand for PVC pipe led to a rapid and significant increase in sales prices for the product, significantly outpacing the increase in resin input costs, leading to increased operating margins within our Plastics segment. PVC pipe prices and resin costs reached historic levels, peaking in 2022. Sales prices have steadily declined since the third quarter of 2022, a trend that continued throughout 2024; however, operating margins remain elevated relative to historical levels.
In the second half of 2022, our sales volumes declined in response to uncertain and competitive market conditions, which continued through the first half of 2023. Robust infrastructure investment plans, particularly in water supply, sewage, and drainage systems, and increased construction activity drove strong distributor and end market demand for PVC pipe beginning in the second half of 2023 and those trends continued throughout 2024.
The market dynamics impacting our Plastics segment resulted in a significant increase in earnings in the last four years compared to historical levels. We anticipate PVC pipe sales prices will continue to decline over time; however, future supply and demand dynamics, as well as other factors, could impact future product prices. We anticipate PVC pipe prices will gradually normalize through 2027. The marketplace dynamics impacting our Plastics segments are fluid and subject to change and may impact our operating results prospectively.
| FINANCIAL AND OTHER METRICS | |||||
Heating Degree Days (HDDs) is a measure of how much (in degrees), and for how long (in days), the outside air temperature was below a certain normalized level. Normal weather conditions are defined as the 20-year average of actual historical weather conditions. This measure is commonly used in calculations relating to the energy consumption required to heat buildings.
Cooling Degree Days (CDDs) is a measure of how much (in degrees), and for how long (in days), the outside air temperature was above a certain normalized level. This measure is commonly used in calculations relating to the energy consumption required to cool buildings.
32
OTP generally bases its forecasted kwh sales and rates on expected consumption under a normal level of HDDs and CDDs over a given period of time in its service territory. Increased or decreased levels of consumption for certain customer classifications are attributed to deviation from the norms and are a significant factor influencing consumption of electricity across our service territory. We present HDDs and CDDs to provide an indication of the impact of weather on kwh sales, revenues and earnings relative to forecast, and on period-to-period results.
| RESULTS OF OPERATIONS | |||||
For a comparison of fiscal year 2023 to 2022, 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, 2023, filed with the SEC on February 14, 2024.
Provided below is a summary and discussion of our operating results on a consolidated basis followed by a discussion of the operating results of each of our segments, Electric, Manufacturing and Plastics. In addition to the segment results, we provide an overview of our Corporate costs. Our Corporate costs do not constitute a reportable segment, but rather consist of unallocated general corporate expenses, such as corporate staff and overhead costs, the results of our captive insurance company and other items excluded from the measurement of segment performance. Corporate costs are added to operating segment totals to reconcile to totals on our consolidated statements of income.
CONSOLIDATED RESULTS
The following table summarizes our consolidated results of operations for the years ended December 31, 2024 and 2023:
| (in thousands) | 2024 | 2023 | $ change | % change | |||||||||||||||||||
| Operating Revenues | $ | 1,330,548 | $ | 1,349,166 | $ | (18,618) | (1.4) | % | |||||||||||||||
| Operating Expenses | 950,298 | 971,247 | (20,949) | (2.2) | |||||||||||||||||||
| Operating Income | 380,250 | 377,919 | 2,331 | 0.6 | |||||||||||||||||||
| Interest Expense | (41,815) | (37,677) | (4,138) | 11.0 | |||||||||||||||||||
| Nonservice Components of Postretirement Benefits | 9,609 | 10,597 | (988) | (9.3) | |||||||||||||||||||
| Other Income | 18,848 | 12,650 | 6,198 | 49.0 | |||||||||||||||||||
| Income Before Income Taxes | 366,892 | 363,489 | 3,403 | 0.9 | |||||||||||||||||||
| Income Tax Expense | 65,230 | 69,298 | (4,068) | (5.9) | |||||||||||||||||||
| Net Income | $ | 301,662 | $ | 294,191 | $ | 7,471 | 2.5 | % | |||||||||||||||
Operating Revenues decreased $18.6 million on a consolidated basis in 2024. Electric segment operating revenues decreased 1% primarily due to decreased fuel recovery and wholesale revenues and the impact of unfavorable weather, partially offset by retail revenue increases due to an interim rate increase in North Dakota in connection with our most recent rate case, as well as increased commercial and industrial sales volumes, and increased rider revenue. Manufacturing segment operating revenues decreased 15% primarily due to lower sales volumes due to soft end market demand across most end markets. Plastics segment operating revenues increased 11% primarily due to increased sales volumes driven by strong customer demand, partially offset by a decrease in sales prices. See our segment disclosures below for additional discussion of items impacting operating revenues.
Operating Expenses decreased $20.9 million in 2024. Electric segment operating expenses decreased primarily due to decreased purchased power costs resulting from lower market energy prices. Operating expenses in our Manufacturing segment decreased primarily due to decreased sales volumes, as discussed above. Operating expenses in our Plastics segment increased primarily due to increased sales volumes, as discussed above. See our segment disclosures below for additional discussion of items impacting operating expenses.
Interest Expense increased $4.1 million in 2024 due to the issuance of an additional $120.0 million of long-term debt at OTP in March, the proceeds of which were used to repay short-term borrowings, fund capital expenditures and support operating activities.
Other Income increased $6.2 million in 2024 primarily due to an increase in investment income earned on our short-term cash equivalent investments and our long-term fixed income investments.
Income Tax Expense decreased $4.1 million in 2024 primarily due to an increase in PTCs produced by our wind and solar generation assets. Our effective tax rate was 17.8% in 2024 and 19.1% in 2023. See Note 13 to our consolidated financial statements included in this report on Form 10-K for additional information regarding factors impacting our effective tax rate.
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ELECTRIC SEGMENT RESULTS
The following table summarizes the operating results of our Electric segment for the years ended December 31, 2024 and 2023:
| (in thousands) | 2024 | 2023 | $ change | % change | |||||||||||||||||||
Retail Revenue | $ | 453,214 | $ | 455,840 | $ | (2,626) | (0.6) | % | |||||||||||||||
Transmission Services Revenue | 53,517 | 52,555 | 962 | 1.8 | |||||||||||||||||||
Wholesale Revenue | 11,077 | 12,459 | (1,382) | (11.1) | |||||||||||||||||||
| Other Electric Revenues | 6,707 | 7,505 | (798) | (10.6) | |||||||||||||||||||
| Total Operating Revenue | 524,515 | 528,359 | (3,844) | (0.7) | |||||||||||||||||||
| Production Fuel | 60,945 | 60,339 | 606 | 1.0 | |||||||||||||||||||
| Purchased Power | 61,561 | 78,292 | (16,731) | (21.4) | |||||||||||||||||||
| Operating and Maintenance Expenses | 190,422 | 191,263 | (841) | (0.4) | |||||||||||||||||||
| Depreciation and Amortization | 82,136 | 75,330 | 6,806 | 9.0 | |||||||||||||||||||
| Property Taxes | 15,662 | 16,614 | (952) | (5.7) | |||||||||||||||||||
| Operating Income | 113,789 | 106,521 | 7,268 | 6.8 | |||||||||||||||||||
Interest Expense | (38,216) | (33,864) | (4,352) | 12.9 | |||||||||||||||||||
| Nonservice Cost Components of Postretirement Benefits | 10,578 | 11,661 | (1,083) | (9.3) | |||||||||||||||||||
| Other Income | 3,268 | 1,754 | 1,514 | 86.3 | |||||||||||||||||||
| Income Before Income Taxes | 89,419 | 86,072 | 3,347 | 3.9 | |||||||||||||||||||
Income Tax (Benefit) Expense | (1,544) | 1,648 | (3,192) | (193.7) | |||||||||||||||||||
| Net Income | $ | 90,963 | $ | 84,424 | $ | 6,539 | 7.7 | % | |||||||||||||||
Electric kwh Sales (in thousands) | 2024 | 2023 | kwh change | % change | |||||||||||||||||||
| Retail kwh Sales | 5,681,268 | 5,772,215 | (90,947) | (1.6) | % | ||||||||||||||||||
| Wholesale kwh Sales | 273,365 | 351,729 | (78,364) | (22.3) | |||||||||||||||||||
| Heating Degree Days | 5,313 | 6,259 | (946) | (15.1) | |||||||||||||||||||
| Cooling Degree Days | 440 | 590 | (150) | (25.4) | % | ||||||||||||||||||
Our Electric segment operating results are impacted by fluctuations in weather conditions and the resulting demand for electricity for heating and cooling. The following table presents heating and cooling degree days as a percent of normal for the years ended December 31, 2024 and 2023:
| 2024 | 2023 | ||||||||||
| Heating Degree Days | 83.7 | % | 98.4 | % | |||||||
| Cooling Degree Days | 93.8 | % | 127.2 | % | |||||||
The following table summarizes the estimated effect on diluted earnings per share of the difference in retail sales under actual weather conditions and expected retail sales under normal weather conditions for the years ended December 31, 2024 and 2023, and between years:
| 2024 vs Normal | 2024 vs 2023 | 2023 vs Normal | |||||||||||||||
| Effect on Diluted Earnings Per Share | $ | (0.13) | $ | (0.15) | $ | 0.02 | |||||||||||
Retail Revenue decreased $2.6 million primarily due to the following:
•A $13.4 million decrease in fuel recovery revenues, primarily due to lower purchased power costs, as described below.
•A $8.1 million decrease in base revenues from the unfavorable impact of weather compared to last year.
The decreases in retail revenue described above were partially offset by the following:
• A $12.4 million increase from an interim rate increase in North Dakota, effective January 1, 2024, in connection with our most recent rate case.
• A $3.2 million increase in rider revenues, including recovery of our continued investments in advanced metering and outage management systems and wind repowering projects.
•Increased sales volumes to commercial and industrial customers, the mix of customer rates compared to the prior year and other factors.
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Purchased Power costs to serve retail customers decreased $16.7 million due to a 17% decrease in the price of purchased power, primarily due to decreased market energy costs, as well as a 5% decrease in the volume of purchased power primarily due to decreased demand resulting from unfavorable weather.
Operating and Maintenance Expense decreased $0.8 million primarily due to decreased vegetative maintenance, outage, transmission tariff and insurance costs, partially offset by increased labor, software and environmental protection costs.
Depreciation and Amortization expense increased $6.8 million primarily due to the placing in service of our metering infrastructure project throughout the year, a full year of depreciation recognized for Hoot Lake Solar, which was placed in service in August 2023, and continued investments in distribution facilities during the year.
Property Taxes decreased $1.0 million due to lower taxes associated with certain wind farm facilities in North Dakota due to a revision of the tax methodology applied to the property and lower taxes in Minnesota.
Interest Expense increased $4.4 million due to the issuance of an additional $120.0 million of long-term debt in March, partially offset by lower interest on short-term borrowings due to lower average borrowings and interest rates compared to the prior year.
Income Tax Expense decreased $3.2 million due to an increase in PTCs produced by our wind and solar generation assets, partially attributable to Hoot Lake Solar going into service in August 2023.
MANUFACTURING SEGMENT RESULTS
The following table summarizes the operating results of our Manufacturing segment for the years ended December 31, 2024 and 2023:
| (in thousands) | 2024 | 2023 | $ change | % change | |||||||||||||||||||
| Operating Revenues | $ | 342,592 | $ | 402,781 | $ | (60,189) | (14.9) | % | |||||||||||||||
| Cost of Products Sold (excluding depreciation) | 267,904 | 310,601 | (42,697) | (13.7) | |||||||||||||||||||
| Selling, General, and Administrative Expenses | 35,203 | 44,545 | (9,342) | (21.0) | |||||||||||||||||||
| Depreciation and Amortization | 20,393 | 18,495 | 1,898 | 10.3 | |||||||||||||||||||
| Operating Income | 19,092 | 29,140 | (10,048) | (34.5) | |||||||||||||||||||
Interest Expense | (2,516) | (2,295) | (221) | 9.6 | |||||||||||||||||||
| Other Income | — | (1) | 1 | (100.0) | |||||||||||||||||||
| Income Before Income Taxes | 16,576 | 26,844 | (10,268) | (38.3) | |||||||||||||||||||
| Income Tax Expense | 2,895 | 5,390 | (2,495) | (46.3) | |||||||||||||||||||
| Net Income | $ | 13,681 | $ | 21,454 | $ | (7,773) | (36.2) | % | |||||||||||||||
Operating Revenues decreased $60.2 million primarily due to a 15% decrease in sales volumes, with declines experienced in the recreational vehicle, agriculture, construction, lawn and garden, and horticulture end markets. Sales volumes decreased due to lower end market demand and inventory management efforts by manufacturers, distributors and dealers. A 28% decline in scrap metal revenues, largely driven by lower production volumes, also contributed to the decrease in operating revenues.
Cost of Products Sold decreased $42.7 million primarily due to lower sales volumes, as described above. In response to declines in end market demand and decreased sales volumes, we reduced our headcount and operating hours and placed employees on temporary furlough during the year, which also reduced our costs. These decreases were partially offset by reduced leveraging of fixed manufacturing costs resulting from the decreased production and sales volumes.
Selling, General, and Administrative Expenses decreased $9.3 million primarily due to decreased employee compensation costs resulting from a decrease in headcount and lower variable compensation driven by financial performance in the current year.
Depreciation and Amortization increased $1.9 million due to capital expenditures during the year, which included investments in facility improvements and purchases of equipment.
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PLASTICS SEGMENT RESULTS
The following table summarizes the operating results for our Plastics segment for the years ended December 31, 2024 and 2023:
| (in thousands) | 2024 | 2023 | $ change | % change | |||||||||||||||||||
| Operating Revenues | $ | 463,441 | $ | 418,026 | $ | 45,415 | 10.9 | % | |||||||||||||||
| Cost of Products Sold (excluding depreciation) | 166,628 | 143,521 | 23,107 | 16.1 | |||||||||||||||||||
| Selling, General, and Administrative Expenses | 20,414 | 16,076 | 4,338 | 27.0 | |||||||||||||||||||
| Depreciation and Amortization | 4,494 | 4,027 | 467 | 11.6 | |||||||||||||||||||
| Operating Income | 271,905 | 254,402 | 17,503 | 6.9 | |||||||||||||||||||
Interest Expense | (590) | (602) | 12 | (2.0) | |||||||||||||||||||
| Other Income | 76 | 14 | 62 | 442.9 | |||||||||||||||||||
| Income Before Income Taxes | 271,391 | 253,814 | 17,577 | 6.9 | |||||||||||||||||||
| Income Tax Expense | 70,644 | 66,066 | 4,578 | 6.9 | |||||||||||||||||||
| Net Income | $ | 200,747 | $ | 187,748 | $ | 12,999 | 6.9 | % | |||||||||||||||
Operating Revenues increased $45.4 million primarily due to a 27% increase in sales volumes driven by customer sales volume growth and strong distributor and end market demand. Sales volumes in 2023 were negatively impacted by distributors and contractors reducing purchase volumes in response to uncertain and competitive market conditions. Although market conditions remain somewhat uncertain, infrastructure investment and active construction across our sales territories contributed to increased distributor and end market demand in 2024. The impact of increased sales volumes was partially offset by decreased sales prices. Our sales prices have steadily declined after peaking in late 2022 and decreased 12% in 2024 compared to the prior year due to continuing changes in market conditions.
Cost of Products Sold increased $23.1 million primarily due to increased sales volumes, as described above. The supply and demand conditions for PVC resin experienced in recent years appear to have normalized and resin costs were less volatile throughout the year than they were in the recent past. The cost of PVC resin and other input materials decreased 13% compared to the prior year, partially offsetting the impact of increased sales volumes.
Selling, General, and Administrative Expenses increased $4.3 million due to costs associated with ongoing litigation regarding the pricing of PVC pipe, which is further described in Note 14 to the consolidated financial statements, as well as increased variable costs associated with our increase in sales volumes and current year financial performance.
CORPORATE
The following table summarizes Corporate results of operations for the years ended December 31, 2024 and 2023:
| (in thousands) | 2024 | 2023 | $ change | % change | |||||||||||||||||||
| Selling, General, and Administrative Expenses | $ | 24,438 | $ | 12,042 | $ | 12,396 | 102.9 | % | |||||||||||||||
| Depreciation and Amortization | 98 | 102 | (4) | (3.9) | |||||||||||||||||||
Operating Income (Loss) | (24,536) | (12,144) | (12,392) | 102.0 | |||||||||||||||||||
Interest Expense | (493) | (916) | 423 | (46.2) | |||||||||||||||||||
| Nonservice Cost Components of Postretirement Benefits | (969) | (1,064) | 95 | (8.9) | |||||||||||||||||||
| Other Income | 15,504 | 10,883 | 4,621 | 42.5 | |||||||||||||||||||
Income (Loss) Before Income Taxes | (10,494) | (3,241) | (7,253) | 223.8 | |||||||||||||||||||
| Income Tax (Benefit) | (6,765) | (3,806) | (2,959) | 77.7 | |||||||||||||||||||
Net Income (Loss) | $ | (3,729) | $ | 565 | $ | (4,294) | (760.0) | % | |||||||||||||||
Selling, General, and Administrative Expenses increased $12.4 million primarily due to increased insurance expense driven by higher claims costs associated with our self-funded insurance programs, as well as increased variable compensation based on the current year financial performance.
Other Income increased $4.6 million primarily due to an increase in investment income earned on our short-term cash equivalent investments and our long-term fixed income investments, primarily due to additional investments made during the year driven by an increase in cash available for investment.
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| REGULATORY MATTERS | |||||
The following provides a summary of OTP's current and recent rate case filings, rate rider filings, and other regulatory filings that have or are expected to have a material impact on our operating results, financial position or cash flows.
RATE CASES
The following includes a summary of electric rate cases as determined in OTP's most recent general rate case in each state:
| Revenue | Allowed | ||||||||||||||||
| Implementation | Requirement | Return on | Return | Equity | |||||||||||||
| Jurisdiction | Date | (in millions) | Rate Base | on Equity | Ratio | ||||||||||||
| Minnesota | 07/01/22 | $ | 209.0 | 7.18 | % | 9.48 | % | 52.50 | % | ||||||||
North Dakota(1)(2) | 03/15/25 | 225.6 | 7.53 | 10.10 | 53.50 | ||||||||||||
South Dakota(3) | 08/01/19 | 35.5 | 7.09 | 8.75 | 52.92 | ||||||||||||
(1) Includes an earnings sharing mechanism to share with North Dakota customers any earnings above an ROE of 10.20%. The mechanism requires 70% of any revenue creating annual earnings in excess of the authorized ROE be returned to customers. | |||||||||||||||||
(2) A compliance filing affirming the implementation date, revenue requirement, return on rate base, allowed return on equity, and equity ratio was made on February 7, 2025, and remained subject to final approval by the NDPSC as of the date of this annual report on Form 10-K. | |||||||||||||||||
(3) Includes an earnings sharing mechanism to share with South Dakota customers any weather-normalized earnings above the authorized ROE of 8.75%. The mechanism requires 50% of any weather-normalized revenue creating annual earnings in excess of the authorized ROE up to a maximum of 9.50% be returned to customers and 100% returns of revenue creating annual earnings above 9.50%. | |||||||||||||||||
North Dakota Rate Case: On November 2, 2023, OTP filed a request with the NDPSC for an increase in revenue recoverable under general rates in North Dakota. In its filing, OTP requested a net increase in annual revenue of $17.4 million, or 8.4%, based on an allowed rate of return on rate base of 7.85% and an allowed rate of ROE of 10.6% on an equity ratio of 53.5% of total capital. The filing also included an interim rate request of a net increase in annual revenue of $12.4 million, or 6.0%, which was approved by the NDPSC on December 13, 2023. Interim rates went into effect on January 1, 2024. On July 3, 2024, OTP filed an update to the original request increasing the amount of the net annual revenue requirement increase from $17.4 million to $22.5 million, or a net increase of 10.9% in annual revenue, to account for certain items identified throughout the regulatory process.
On December 30, 2024, the NDPSC approved a settlement agreement between OTP and certain interested parties in the general rate case and issued its written order on final rates. The key provisions of the order include a revenue requirement of $225.6 million, based on a return on rate base of 7.53%, and an allowed ROE of 10.10% on an equity ratio of 53.5%. The net annual revenue requirement includes a net increase of $13.1 million, or 6.18%. OTP’s revenue requirement was reduced by approximately $3.0 million primarily due to the inclusion of forecasted PTCs plus adjustments for new customer load additions, which were not included in OTP’s updated request filed on July 3, 2024. Through the settlement of the case, the parties also agreed to establish an earnings sharing mechanism, whereby 70% of actual earnings in excess of a 10.20% ROE would be returned to customers, with OTP retaining the remaining 30%.
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RATE RIDERS
The following table includes a summary of substantial pending and recently concluded rate rider proceedings:
| Recovery | Filing | Amount | Effective | |||||||||||||||||||||||||||||||||||
| Mechanism | Jurisdiction | Status | Date | (in millions) | Date | Notes | ||||||||||||||||||||||||||||||||
| RRR - 2023 | MN | Approved | 11/01/22 | $17.5 | 07/01/23 | Recovery of Hoot Lake Solar costs, Ashtabula III costs, and true up for PTCs from Merricourt. | ||||||||||||||||||||||||||||||||
| ECO - 2023 | MN | Approved | 04/03/23 | 9.7 | 10/01/23 | Recovery of energy conservation improvement costs as well as a demand side management financial incentive. | ||||||||||||||||||||||||||||||||
ECO - 2024 | MN | Approved | 04/01/24 | 8.8 | 10/01/24 | Recovery of energy conservation improvement costs as well as a demand side management financial incentive. | ||||||||||||||||||||||||||||||||
| RRR - 2024 | MN | Approved | 12/04/23 | 8.0 | 09/01/24 | Recovery of Hoot Lake Solar costs, Ashtabula III costs, wind upgrade project costs at our four owned wind facilities, and true up of PTCs for Merricourt. | ||||||||||||||||||||||||||||||||
EUIC - 2025 | MN | Approved | 05/03/24 | 4.1 | 02/01/25 | Recovery of advanced metering infrastructure, outage management system, geographic information system, and demand response projects. | ||||||||||||||||||||||||||||||||
| RRR - 2023 | ND | Approved | 12/30/22 | 12.2 | 05/01/23 | Recovery of Merricourt, Ashtabula III and other costs. | ||||||||||||||||||||||||||||||||
| RRR - 2022 | ND | Approved | 01/05/22 | 7.8 | 04/01/22 | Recovery of Merricourt costs, Ashtabula III costs, and deferred taxes and PTCs. | ||||||||||||||||||||||||||||||||
| TCR - 2023 | ND | Approved | 09/15/22 | 7.5 | 01/01/23 | Recovery of transmission project costs. | ||||||||||||||||||||||||||||||||
| TCR - 2024 | ND | Approved | 11/02/23 | 4.5 | 01/01/24 | Recovery of transmission project costs. | ||||||||||||||||||||||||||||||||
| GCR - 2022 | ND | Approved | 03/01/22 | 3.3 | 07/01/22 | Annual update to generation cost recovery rider. | ||||||||||||||||||||||||||||||||
| MDT - 2023 | ND | Approved | 07/08/22 | 3.1 | 01/01/23 | Recovery of advanced metering infrastructure, outage management system and demand response projects. | ||||||||||||||||||||||||||||||||
TCR - 2025 | ND | Approved | 09/16/24 | 3.1 | 01/01/25 | Recovery of transmission project costs. | ||||||||||||||||||||||||||||||||
PIR - 2024 | SD | Approved | 06/03/24 | 3.2 | 09/01/24 | Recovery of Ashtabula III, Merricourt, Astoria Station, wind upgrade projects, Advanced Grid Infrastructure project costs, and impact of load growth credits. | ||||||||||||||||||||||||||||||||
PIR - 2025 | SD | Requested | 12/20/24 | 3.2 | 09/01/25 | Recovery of Ashtabula III, Merricourt, Astoria Station, wind upgrade projects, advanced metering infrastructure, outage management system, demand response system, and impact of load growth credits. | ||||||||||||||||||||||||||||||||
| PIR - 2022 | SD | Approved | 06/01/22 | 3.0 | 09/01/22 | Recovery of Ashtabula III, Merricourt, Astoria Station, Advanced Grid Infrastructure project costs, and impact of load growth credits. | ||||||||||||||||||||||||||||||||
| TCR - 2023 | SD | Approved | 11/01/22 | 3.0 | 03/01/23 | Recovery of transmission project costs. | ||||||||||||||||||||||||||||||||
RESOURCE PLANNING
Minnesota
In May 2024, the MPUC approved OTP’s 2023 to 2037 IRP. Consistent with MPUC practice, the decision was made during deliberations by oral vote and was finalized in a written order issued in July 2024.
The MPUC:
•Directed OTP to procure the following generation resources, subject to additional regulatory review and approval:
◦200 to 300 MW of solar generation by November 1, 2027, or as soon as practicable thereafter,
◦150 to 200 MW of wind generation by December 31, 2029, or as soon as practicable thereafter,
◦20 to 75 MW of battery storage by December 31, 2029, or as soon as practicable thereafter;
•Approved the project to add on-site liquified natural gas storage at our Astoria Station natural gas plant by 2027;
•Directed OTP to designate the Minnesota share of the jointly owned Coyote Station coal-fired plant as an Available Maximum Emergency (AME) resource beginning in 2026 and ending no later than December 2031. If the designation as an AME resource is found to not be feasible, then Minnesota customers shall not continue to pay for or depend on capacity or energy from Coyote Station past 2028; and
•Directed OTP to commence activities to no longer serve Minnesota customers with capacity or energy from Coyote Station as soon as feasible and no later than December 31, 2031.
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Under the MPUC’s order, OTP will file its next IRP in May 2026. In this filing, the company will include, among other options, an analysis considering the continued operation of Big Stone Plant with AME.
North Dakota
In December 2024, the NDPSC issued its final order on OTP's IRP. The order stipulated that the commission does not support the addition of new wind or solar generation or battery storage through 2030. Therefore, none of the costs or benefits of the new renewable and battery storage assets in OTP's IRP approved by the MPUC will be assigned to North Dakota customers, including any that may be physically located in North Dakota. In addition, at an informal hearing in July 2024, the NDPSC denied our request for an Advanced Determination of Prudence (ADP) for the on-site liquified natural gas storage at Astoria Station, a project that was part of OTP's IRP approved by the MPUC. We continue to evaluate the benefits of on-site fuel storage at Astoria Station and the development of this project in the future.
| LIQUIDITY | |||||
LIQUIDITY OVERVIEW
We believe our financial condition is strong and our cash and cash equivalents, 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, fund our capital expenditure program and satisfy our obligations as they become due. Our liquidity, including our operating cash flows and access to capital markets, could be impacted by macroeconomic factors outside of our control, including higher interest rates and debt capital costs, and diminished credit availability. In addition, our liquidity could be impacted by non-compliance with certain financial covenants under our various debt instruments. As of December 31, 2024, we were in compliance with all financial covenants (see the Financial Covenant section under Capital Resources below).
The following table presents the status of our lines of credit as of December 31, 2024:
| 2024 | |||||||||||||||||||||||
| (in thousands) | Line Limit | Amount Outstanding | Letters of Credit | Amount Available | |||||||||||||||||||
| OTC Credit Agreement | $ | 170,000 | $ | — | $ | — | $ | 170,000 | |||||||||||||||
| OTP Credit Agreement | 220,000 | 69,615 | 8,772 | 141,613 | |||||||||||||||||||
| Total | $ | 390,000 | $ | 69,615 | $ | 8,772 | $ | 311,613 | |||||||||||||||
OTC and OTP are each party to separate credit agreements (the OTC Credit Agreement and OTP Credit Agreement, respectively) which provide for unsecured revolving lines of credit. Should additional liquidity be needed, the OTC Credit Agreement includes an accordion feature allowing us to increase the amount available to $290 million, subject to certain terms and conditions. The OTP Credit Agreement also includes an accordion feature allowing OTP to increase that facility to $300 million, subject to certain terms and conditions.
As of December 31, 2024, we had $311.6 million of available liquidity under our credit agreements and $294.7 million of available cash and cash equivalents, resulting in total available liquidity of $606.3 million, compared to total available liquidity of $479.8 million as of December 31, 2023.
CASH FLOWS
The following is a discussion of our cash flows for the years ended December 31, 2024 and 2023:
| (in thousands) | 2024 | 2023 | |||||||||
| Net Cash Provided by Operating Activities | $ | 452,731 | $ | 404,499 | |||||||
Net Cash Provided by Operating Activities increased $48.2 million primarily due to a decrease in working capital and increased net income. In our Plastics segment, sales and related receivable balances were less volatile than the prior year where sales and related receivable balances increased in the later part of the year. This resulted in decreased working capital in the current year compared to the prior year. Working capital also decreased due to an increase in payables in our Electric segment, due to the timing of capital investment spending, and decreases in receivables and inventories in our Manufacturing segment, due to decreased sales and production volumes during the later part of the current year.
Market dynamics experienced by our Plastics segment businesses in 2024 and 2023 resulted in a significant increase in our overall cash from operations compared to prior periods. We anticipate our cash from operations in future years will decline from current levels consistent with the anticipated decline in Plastics segment earnings.
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| (in thousands) | 2024 | 2023 | |||||||||
| Net Cash Used in Investing Activities | $ | 411,374 | $ | 289,287 | |||||||
Net Cash Used in Investment Activities increased $122.1 million primarily due to an increase in capital expenditures. Capital expenditures during the year included additional investments in our wind repowering and advanced metering and outage management projects at OTP, as well as continued investments in our manufacturing facility expansion projects in Arizona and Georgia. A $50.1 million investment in U.S. treasuries made during the year to secure a fixed rate of return until their maturity in September 2026 also contributed to the increase in net cash used in investing activities.
| (in thousands) | 2024 | 2023 | |||||||||
Net Cash Provided by (Used in) Financing Activities | $ | 22,921 | $ | (3,835) | |||||||
Net Cash Provided by (Used in) Financing Activities increased $26.8 million compared to the prior year. Financing activities during the year included the issuance of $120.0 million of long-term debt at OTP, the proceeds of which were used to repay short-term borrowings under the OTP credit agreement, fund Electric segment construction expenditures and support operating activities. We manage the capital structure of OTP independently from our consolidated financial position to ensure compliance with the capital structure approved through regulation; therefore, our decision to issue long-term debt at OTP is not impacted by our consolidated cash and cash equivalent position.
Financing activities during the year also included net repayments of short-term debt of $11.8 million compared to net short-term borrowings of $73.2 million in 2023, and in 2024, we made dividend payments of $78.3 million compared to $73.1 million in 2023.
| CAPITAL REQUIREMENTS | |||||
CAPITAL EXPENDITURES
Our capital expenditure plan includes investments in electric generation facilities, transmission and distribution lines and facilities, manufacturing facilities and upgrades, equipment used in the manufacturing process, and computer hardware and information systems. Our capital expenditure plan is subject to review and is revised in light of changes in demands for energy, technology, environmental laws, regulatory approvals, business expansion opportunities, the costs of labor, materials and equipment, and our overall financial condition.
The following provides a summary of capital expenditures for the years ended December 31, 2024 and 2023 for our Electric segment and non-electric businesses and anticipated capital expenditures for the five-year period 2025 through 2029:
| (in millions) | 2023 | 2024 | 2025 | 2026 | 2027 | 2028 | 2029 | Total 2025 - 2029 | ||||||||||||||||||||||||||||||||||||||||||
| Electric Segment: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Renewable Generation | $ | 106 | $ | 134 | $ | 101 | $ | 127 | $ | 118 | $ | 179 | $ | 4 | $ | 529 | ||||||||||||||||||||||||||||||||||
| Transmission | 49 | 60 | 59 | 93 | 162 | 114 | 100 | 528 | ||||||||||||||||||||||||||||||||||||||||||
| Distribution | 45 | 46 | 37 | 37 | 36 | 37 | 34 | 181 | ||||||||||||||||||||||||||||||||||||||||||
| Other | 41 | 61 | 54 | 51 | 31 | 27 | 25 | 188 | ||||||||||||||||||||||||||||||||||||||||||
| Total Electric Segment | 241 | 301 | 251 | 308 | 347 | 357 | 163 | 1,426 | ||||||||||||||||||||||||||||||||||||||||||
| Manufacturing and Plastics Segments | 46 | 58 | 27 | 27 | 27 | 25 | 23 | 129 | ||||||||||||||||||||||||||||||||||||||||||
| Total Capital Expenditures | $ | 287 | $ | 359 | $ | 278 | $ | 335 | $ | 374 | $ | 382 | $ | 186 | $ | 1,555 | ||||||||||||||||||||||||||||||||||
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CONTRACTUAL AND OTHER OBLIGATIONS
The following table summarizes our contractual obligations on December 31, 2024 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 | $ | 1,017 | $ | 70 | $ | 122 | $ | 70 | $ | 755 | |||||||||||||||||||
| Interest on Debt Obligations | 700 | 42 | 81 | 71 | 506 | ||||||||||||||||||||||||
| Coal Contracts | 441 | 24 | 50 | 53 | 314 | ||||||||||||||||||||||||
| Land Easements | 62 | 2 | 4 | 4 | 52 | ||||||||||||||||||||||||
| Postretirement Benefit Obligations | 65 | 5 | 11 | 11 | 38 | ||||||||||||||||||||||||
| Operating Lease Obligations | 35 | 6 | 10 | 6 | 13 | ||||||||||||||||||||||||
Other Obligations | 11 | 2 | 2 | 1 | 6 | ||||||||||||||||||||||||
Total Contractual Obligations | $ | 2,331 | $ | 151 | $ | 280 | $ | 216 | $ | 1,684 | |||||||||||||||||||
Coal contract obligations are based on estimated coal consumption and costs for the delivery of coal to Coyote Station from Coyote Creek Mining Company (CCMC) under the Lignite Sales Agreement (LSA) that ends in 2040. Postretirement benefit obligations include estimated cash expenditures for the payment of retiree medical and life insurance benefits and supplemental pension benefits under our unfunded Executive Survivor and Supplemental Retirement Plan (ESSRP), but do not include amounts to fund our noncontributory funded pension plan, as we are not currently required to make any contributions to that plan. OTP also has contractual agreements for the purchase of capacity and wind-generated energy. Generally, the terms of OTP's wind power purchase agreements require OTP to purchase all of the electricity generated by a particular wind farm, but do not include fixed or minimum payments.
On October 30, 2024, OTP entered into an agreement to acquire the assets of a solar facility currently under development. Under the terms of the agreement, the purchase price is equal to $23.6 million, plus the reimbursement of certain interconnection costs and costs to purchase and store the main power transformer. Closing of the transaction is expected to occur in late 2025 or early 2026.
COMMON STOCK DIVIDENDS
We paid dividends to our shareholders totaling $78.3 million, or $1.87 per share, in 2024. The determination of the amount of future cash dividends to be paid will depend on, among other things, our financial condition, our actual or expected level of earnings and cash flows from operations, the level of our capital expenditures and our future business prospects. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by OTC subsidiaries to OTC. These intercompany distributions serve as the primary source of funding for dividends paid to our shareholders. See Note 15 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 4, 2025, our Board of Directors approved a quarterly dividend of $0.525 per common share.
| CAPITAL RESOURCES | |||||
Financial flexibility is provided by operating cash flows, unused lines of credit, access to capital markets and alternative financing arrangements such as leasing. Debt financing will be required in the five-year period from 2025 through 2029 to refinance maturing debt and to finance our planned capital investments. Our financing plans are subject to change and are impacted by our planned level of capital investments, decisions to reduce borrowings under our lines of credit, to refund or retire early any of our presently outstanding debt, to complete acquisitions or to use capital for other purposes.
REGISTRATION STATEMENTS
On May 3, 2024, we filed two registration statements with the SEC, replacing two previously filed registration statements upon their expiration. The first statement, a shelf registration, allows us to offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the registration statement. No new equity, debt, or other securities have been issued pursuant to this registration statement. The second registration statement allows for the issuance of up to 1,500,000 common shares under our Automatic Dividend Reinvestment and Share Purchase Plan, which provides our common shareholders, retail customers of OTP and other interested investors a method of purchasing our common shares by reinvesting their dividends and/or making optional cash investments. Shares purchased under the plan may be newly issued common shares or common shares purchased on the open market. As of December 31, 2024, there were 1,429,531 shares available for purchase or issuance under the plan. Both registration statements expire in May 2027.
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SHORT-TERM DEBT
The OTC Credit Agreement and OTP Credit Agreement provide for unsecured revolving lines of credit. In December 2024, the credit agreements were amended to extend the maturity date of each credit facility and amend certain financial covenants. The OTP Credit Agreement was also amended to increase the borrowing limit. The agreements generally bear interest at the Secured Overnight Financing Rate (SOFR) plus an applicable credit spread, which is subject to adjustment based on the credit ratings of the borrower. The weighted-average interest rate on all outstanding borrowings as of December 31, 2024 and 2023 was 5.61% and 6.70%.
The following is a summary of key provisions and borrowing information as of and for the year ended December 31, 2024:
LONG-TERM DEBT
In March 2024, OTP entered into a Note Purchase Agreement pursuant to which OTP issued, in a private placement transaction, $120.0 million of senior unsecured notes consisting of (a) $60.0 million of 5.48% Series 2024A Senior Unsecured Notes due April 1, 2034, and (b) $60.0 million of 5.77% Series 2024B Senior Unsecured Notes due April 1, 2054. The proceeds of the notes were used to repay existing short-term borrowings, fund capital expenditures and for general corporate purposes.
As of December 31, 2024, we had $947.0 million of principal outstanding under long-term debt arrangements. Note 10 to our consolidated financial statements included in this report on Form 10-K includes information regarding these instruments. The agreements generally provide for unsecured borrowings at fixed rates of interest with maturities ranging from 2026 to 2054.
Financial Covenants
Our short- and long-term debt agreements require OTC and OTP to maintain certain financial covenants. As of December 31, 2024, we were in compliance with these financial covenants as further described below:
OTC, under its financial covenants, may not permit its ratio of interest-bearing debt to total capitalization to exceed 0.60 to 1.00 or 0.65 to 1.00, depending on the debt agreement, 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, 2024, OTC's interest-bearing debt to total capitalization was 0.38 to 1.00, OTC's interest and dividend coverage ratio was 10.00 to 1.00 and OTC had no priority indebtedness outstanding.
OTP, under its financial covenants, may not permit its ratio of interest-bearing debt to total capitalization to exceed 0.60 to 1.00 or 0.65 to 1.00, depending on the debt agreement, 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 20% of its total capitalization. As of December 31, 2024, OTP's interest-bearing debt to total capitalization was 0.47 to 1.00, OTP's interest and dividend coverage ratio was 3.34 to 1.00 and OTP 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 current credit ratings of OTC and OTP are summarized below:
| Otter Tail Corporation | Otter Tail Power Company | ||||||||||||||||||||||
| Moody's | Fitch | S&P | Moody's | Fitch | S&P | ||||||||||||||||||
| Corporate Credit/Long-Term Issuer Default Rating | Baa2 | BBB | BBB | A3 | BBB+ | BBB+ | |||||||||||||||||
| Senior Unsecured Debt | n/a | BBB | n/a | n/a | A- | n/a | |||||||||||||||||
| Outlook | Stable | Stable | Stable | Negative | Stable | Stable | |||||||||||||||||
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CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES | |||||
The discussion and analysis of our results of operations are based on financial statements prepared in accordance with generally accepted accounting principles in the United States of America. Certain of our accounting policies require management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the preparation of our consolidated financial statements. While we believe the estimates, assumptions and judgments we use in preparing our consolidated financial statements are appropriate and are based on the best available information, they are subject to future events and uncertainties regarding their outcome and therefore actual results may materially differ from these estimates. Management has discussed the application of these critical accounting policies and the development of these estimates with the Audit Committee of our Board of Directors. The following critical accounting policies affect the most significant judgments and estimates used in the preparation of our consolidated financial statements.
REGULATORY ACCOUNTING
Our utility business is subject to regulation of rates and other matters by state utility commissions in Minnesota, North Dakota and South Dakota and by the FERC for certain interstate operations. Accordingly, our utility business must adhere to the accounting requirements of regulated operations, which requires the recognition of regulatory assets and regulatory liabilities for amounts that otherwise would impact the statements of income or comprehensive income when it is probable that such amounts will be collected from customers or credited to customers through the rate-making process. This guidance also provides recognition criteria for adjustments to rates outside of a general rate case proceeding, which are provided to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. Regulatory assets generally represent costs that have been incurred but have been deferred because future recovery from customers, as established through the rate-making process, is probable. Regulatory liabilities generally represent amounts to be refunded to customers or amounts currently collected from customers for future costs.
We assess the probability of recovery of regulatory assets and the obligations arising from regulatory liabilities on a quarterly basis. Our probability estimates incorporate numerous factors, including recent rate making decisions, historical precedents for similar matters, the regulatory environments in which we operate and the impact these incurred costs may have on our customers. Changes in our assessments regarding the likelihood of recovery or settlement of our regulatory assets and liabilities may have a material impact on our operating results and financial position. Further, if we determine that all or a portion of our utility business no longer meets the criteria for continued application of regulatory accounting, or our regulators disallow recovery of a previously incurred cost or eliminate a regulatory liability, we would be required to remove the associated regulatory assets and liabilities from our consolidated balance sheets and recognize those amounts in the consolidated statements of income as an expense or income item, or in the consolidated statements of comprehensive income as a loss or gain, in the period in which this accounting treatment is no longer applicable.
As of December 31, 2024 and 2023, we had regulatory assets of $108.6 million and $111.8 million and regulatory liabilities of $318.2 million and $302.0 million. If future recovery of amounts recorded as regulatory assets was no longer probable, we would be required to recognize an expense or loss in the period in which recovery was deemed to no longer be probable.
PENSION AND OTHER POSTRETIREMENT BENEFITS OBLIGATIONS AND COSTS
Pension and postretirement benefit liabilities and expenses are determined by actuaries using numerous assumptions, including a discount rate, an expected return on plan assets, a rate of compensation increase and healthcare cost-trend rates. See Note 11 to our consolidated financial statements included in this report on Form 10-K for additional information on our pension and postretirement benefit plans and related assumptions.
These benefits, for any individual employee, can be earned and related expenses can be recognized and a liability accrued over periods of up to 30 or more years. These benefits can be paid out for up to 40 or more years after an employee retires. Estimates of liabilities and expenses related to these benefits are among our most critical accounting estimates. Although deferral and amortization of fluctuations in actuarially determined benefit obligations and expenses are provided for when actual results on a year-to-year basis deviate from long-range assumptions, compensation increases and healthcare cost increases or a reduction in the discount rate applied from one year to the next can significantly increase our benefit expenses in the year of the change. Likewise, compensation decreases and healthcare cost decreases or an increase in the discount rate applied from one year to the next can significantly decrease our benefit expenses in the year of the change. Also, a change in the expected rate of return on pension plan assets in our funded pension plan or realized rates of return on plan assets that are well above or below assumed rates of return or a change in the anticipated life expectancy of plan participants could result in significant increases or decreases in recognized pension benefit expenses in the year of the change or for many years thereafter because actuarial losses can be amortized over the average remaining service lives of active employees.
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We estimate the discount rate through the use of a hypothetical bond portfolio method, which incorporates yields on a collection of high credit quality bonds that produce cash flows similar to our anticipated future benefit payments. We estimate the assumed long-term rate of return on plan assets based on asset category studies using historical market returns achieved by our asset portfolio allocation over long-term periods, as well as long-term projected return levels. Other assumptions are developed by reference to available trend or historical data adjusted as necessary for future expectations.
On December 31, 2024, the discount rates used to measure our pension plan and postretirement healthcare obligations were 5.70% and 5.61%, a thirteen and eight basis point increase, respectively, from the estimates used on December 31, 2023. Our estimates used to determine benefit cost for 2024 included a discount rate of 5.57% for pension benefits and 5.53% for postretirement healthcare costs, a six and one basis point increase, respectively, from 2023 estimates. In addition, we estimated our assumed rate of return on pension assets to be 7.00% for 2024, which was unchanged from our 2023 estimate.
The following table summarizes the impact on 2024 pension and postretirement costs for a 25 basis point increase or decrease, holding all other variables constant, on certain key assumptions:
| (in thousands) | +0.25 | -0.25 | |||||||||
| Pension Plan: | |||||||||||
| Discount Rate | $ | (96) | $ | 931 | |||||||
| Rate of Increase in Future Compensation | 573 | (424) | |||||||||
| Long-Term Return on Plan Assets | (911) | 911 | |||||||||
| Other Postretirement Benefits: | |||||||||||
| Discount Rate | (14) | 15 | |||||||||
For 2025, we expect pension and other postretirement benefit income to be $4.3 million compared to $8.5 million of income in 2024 due to the impacts of updated actuarial assumptions. See additional information at Note 11 of the consolidated financial statements.
Subsequent increases or decreases in actual rates of return on plan assets over assumed rates, increases or decreases in the discount rate, increases in future compensation levels and increases in retiree healthcare cost inflation rates could significantly change projected costs.
We believe the estimates made for our pension and other postretirement benefits are reasonable based on the information that is known at the point in time the estimates are made. These estimates and assumptions are subject to a number of variables and are subject to change.
GOODWILL IMPAIRMENT
Goodwill is required to be evaluated annually for impairment and more frequently as events or circumstances require. Goodwill is tested for impairment at the reporting unit level. We have identified two reporting units which carry a material amount of goodwill, BTD Manufacturing, our contract metal fabrication business, and our Plastics segment. As of December 31, 2024, BTD Manufacturing and our Plastics segment carried a goodwill balance of $18.1 million and $19.3 million, respectively.
We historically tested goodwill for impairment as of December 31st each year; however, in 2024, we elected to change the date of our annual goodwill impairment test to October 1st. We believe this new testing date allows us to better align our annual goodwill impairment testing procedures with our year-end financial reporting, as well as our annual budgeting and forecasting process. This change did not delay, accelerate or avoid the recognition of an impairment charge.
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 using income and market approaches. Our income approach uses 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. Our market approach includes estimating the fair value of our reporting units by reference to various market indications of value, including fair value estimates using multiples derived from comparable enterprise values to earnings before interest, taxes, depreciation and amortization (EBITDA) of select peer companies, 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
44
estimated terminal growth rate and the selection of an appropriate weighted-average cost of capital, among others. Our market approaches require significant judgment in selecting comparable peer companies and comparable sales transactions and from these peer groups selecting an appropriate EBITDA multiple and indication of fair value. In addition, weighting the indications of fair value between the income and market approaches to arrive at a single fair value estimate for each reporting unit also requires judgment.
Our goodwill impairment testing performed in the fourth quarter of 2024 indicated no impairment was present for either reporting unit and the estimated fair value of each reporting unit substantially exceeded the respective carrying value. As part of our testing, we perform various sensitivity analyses to understand if our conclusions are sensitive to changes in certain assumptions. A 3% decrease in projected operating revenues, a one hundred basis point decrease in projected gross profit margins, a one hundred basis point decrease in projected terminal growth rate, a 50 basis point increase in weighted-average cost of capital or a 1.0x decrease in the assumed EBITDA multiple would not lead to a goodwill impairment charge for either reporting unit.
We believe the estimates and assumptions used in our impairment assessments are reasonable and based on the best information available. However, these estimates and assumptions include an inherent degree of uncertainty. Significant adverse changes in our expectations for any of these estimates could result in an impairment charge in a future period which may materially impact our operating results and financial position.
| 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 commodity price and interest rate risk.
Commodity Price Risk
Our Electric segment business is exposed to market risk arising from changes in commodity prices for wholesale energy and natural gas. OTP purchases energy in the wholesale market to supplement its own electricity generation and to respond to changes in demand and variability in generating plant output. In addition, OTP procures natural gas as a fuel source for its combustion turbine peaking facilities. OTP's exposure to price risk for these commodities is largely mitigated by the current ratemaking process and regulatory framework, which generally allows recovery of purchased power and fuel costs from our electric customers.
OTP, where prudent, seeks to further manage its exposure to commodity price variability and reduce volatility in prices for its retail customers through the use of derivative instruments, primarily financial swap agreements. OTP does not engage in derivative and hedging activities for trading purposes. As of December 31, 2024, OTP was party to financial swap agreements with an aggregate notional amount of 167,200 megawatt-hours of electricity with various settlement dates throughout 2025. As of December 31, 2024, the aggregate fair value of these instruments was $2.0 million, reflected as a liability on our consolidated balance sheets. Holding other variables constant, a ten percent change in energy prices would have had an approximate $0.9 million impact on the fair value of these instruments.
Our Manufacturing and Plastics segment businesses are exposed to market risk arising from changes in commodity prices for certain raw material inputs, including steel, aluminum and PVC and other plastic resins. We manage commodity price risk by attempting to pass changes in the cost of these input materials through to our customers. If our efforts to manage commodity price risk are unsuccessful, the operating revenues and earnings of our Manufacturing and Plastics segment could be impacted.
We do not engage in any hedging activities within our Manufacturing and Plastics segments to manage our commodity price risk.
Interest Rate Risk
Our exposure to interest rate risk arises from our outstanding short-term debt which is subject to variable rates of interest based on benchmark interest rates, primarily SOFR, and our cash equivalent investments, which earn income at a rate that fluctuates daily, based on changes in U.S. treasury rates. As of December 31, 2024 and 2023, we had $69.6 million and $81.4 million of short-term debt outstanding. Holding other variables constant, a 100 basis point change in interest rates during 2024 would have had an approximate $0.4 million impact to interest expense in 2024 based on our average outstanding short-term debt during the year. As of December 31, 2024 and 2023, we had $282.0 million and $219.7 million invested in cash equivalent investments. Holding other variables constant, a 100 basis point change in the average interest rates during 2024 would have had an approximate $2.3 million impact to our investment income in 2024, based on our average outstanding investment balance during the year.
All of our outstanding long-term debt obligations as of December 31, 2024 and 2023 had fixed interest rates and were not subject to material interest rate risk. We manage our interest rate risk through the issuance of fixed-rate debt with varying maturities, by limiting the amount of variable interest rate debt and the utilization of short-term borrowings to allow flexibility in the timing and placement of long-term debt.
We have not used hedging instruments to manage interest risk arising from our portfolio of borrowings. We maintain a ratio of fixed-rate debt to total debt within a certain range. It is our policy to enter into interest rate transactions and other financial
45
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.
46
| ITEM 8. | FINANCIAL STATEMENTS | ||||
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Otter Tail Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Otter Tail Corporation and subsidiaries (the "Company") as of December 31, 2024 and 2023, 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, 2024, 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, 2024, 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, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, 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, 2024, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.
Basis for Opinions
The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report Regarding Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we
47
are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Matters—Impact of Rate Regulation on the Financial Statements—Refer to Notes 1 and 6 to the financial statements
Critical Audit Matter Description
The Company’s regulated Electric segment accounts for the financial effects of regulation in accordance with ASC 980, Regulated Operations. This guidance allows for the recording of a regulatory asset or liability for certain costs or credits which otherwise would be recognized in the statement of income or comprehensive income based on an expectation that the cost will be recovered or returned in future rates. This guidance also provides for adjustments to rates outside of a general rate case proceeding to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations.
The Company is subject to regulation of rates and other matters by state and federal regulatory agencies (collectively, the “Commissions”), which have jurisdiction with respect to the rates of electric distribution companies in Minnesota, North Dakota and South Dakota. The Company assesses the probability of recovery of regulatory assets and the obligations arising from regulatory liabilities on a quarterly basis. Probability estimates incorporate numerous factors, including recent rate making decisions, historical precedents for similar matters, the regulatory environments in which the Company operates, and the impact that incurred costs may have on customers.
There is a risk that the Commissions will not approve full recovery of the costs of providing utility service or full recovery of all amounts invested in the utility business and a reasonable return on that investment. As a result, we identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include the recording of regulatory assets for certain costs which otherwise would be recognized in the statement of income or comprehensive income based on an expectation that the costs will be recovered in future rates and the recording of regulatory liabilities for certain credits which would otherwise be recognized in the statement of income or comprehensive income based on an expectation that the amount will be returned to customers in future rates. Given that management’s accounting judgements are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities, the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates, and the related disclosures in the notes to the financial statements.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions for the Company, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
•We obtained an analysis from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ Deloitte & Touche LLP
Minneapolis, Minnesota
February 19, 2025
We have served as the Company's auditor since 1944.
48
OTTER TAIL CORPORATION
CONSOLIDATED BALANCE SHEETS
| December 31, | |||||||||||
| (in thousands, except share data) | 2024 | 2023 | |||||||||
| Assets | |||||||||||
| Current Assets | |||||||||||
| Cash and Cash Equivalents | $ | 294,651 | $ | 230,373 | |||||||
| Receivables, net of allowance for credit losses | 145,964 | 157,143 | |||||||||
| Inventories | 148,885 | 149,701 | |||||||||
| Regulatory Assets | 9,962 | 16,127 | |||||||||
| Other Current Assets | 30,579 | 16,826 | |||||||||
| Total Current Assets | 630,041 | 570,170 | |||||||||
| Noncurrent Assets | |||||||||||
| Investments | 121,177 | 62,516 | |||||||||
| Property, Plant and Equipment, net of accumulated depreciation | 2,692,460 | 2,418,375 | |||||||||
| Regulatory Assets | 98,673 | 95,715 | |||||||||
| Intangible Assets, net of accumulated amortization | 5,743 | 6,843 | |||||||||
| Goodwill | 37,572 | 37,572 | |||||||||
| Other Noncurrent Assets | 66,416 | 51,377 | |||||||||
| Total Noncurrent Assets | 3,022,041 | 2,672,398 | |||||||||
| Total Assets | $ | 3,652,082 | $ | 3,242,568 | |||||||
| Liabilities and Shareholders' Equity | |||||||||||
| Current Liabilities | |||||||||||
| Short-Term Debt | $ | 69,615 | $ | 81,422 | |||||||
| Accounts Payable | 113,574 | 94,428 | |||||||||
| Accrued Salaries and Wages | 34,398 | 38,134 | |||||||||
| Accrued Taxes | 17,314 | 26,590 | |||||||||
| Regulatory Liabilities | 29,307 | 25,408 | |||||||||
| Other Current Liabilities | 45,582 | 43,775 | |||||||||
| Total Current Liabilities | 309,790 | 309,757 | |||||||||
| Noncurrent Liabilities and Deferred Credits | |||||||||||
| Pension Benefit Liability | 32,614 | 33,101 | |||||||||
| Other Postretirement Benefits Liability | 27,385 | 27,676 | |||||||||
| Regulatory Liabilities | 288,928 | 276,547 | |||||||||
| Deferred Income Taxes | 267,745 | 237,273 | |||||||||
| Deferred Tax Credits | 14,990 | 15,172 | |||||||||
| Other Noncurrent Liabilities | 98,397 | 75,977 | |||||||||
| Total Noncurrent Liabilities and Deferred Credits | 730,059 | 665,746 | |||||||||
Commitments and Contingencies (Note 14) | |||||||||||
| Capitalization | |||||||||||
| Long-Term Debt | 943,734 | 824,059 | |||||||||
| Shareholders' Equity | |||||||||||
Common Stock: 50,000,000 shares authorized of $5 par value; 41,827,967 and 41,710,521 outstanding at December 31, 2024 and 2023 | 209,140 | 208,553 | |||||||||
| Additional Paid-In Capital | 429,089 | 426,963 | |||||||||
| Retained Earnings | 1,029,738 | 806,342 | |||||||||
| Accumulated Other Comprehensive Income | 532 | 1,148 | |||||||||
| Total Shareholders' Equity | 1,668,499 | 1,443,006 | |||||||||
| Total Capitalization | 2,612,233 | 2,267,065 | |||||||||
| Total Liabilities and Shareholders' Equity | $ | 3,652,082 | $ | 3,242,568 | |||||||
See accompanying notes to consolidated financial statements.
49
OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
| Years Ended December 31, | |||||||||||||||||
| (in thousands, except per-share amounts) | 2024 | 2023 | 2022 | ||||||||||||||
| Operating Revenues | |||||||||||||||||
| Electric | $ | 524,515 | $ | 528,359 | $ | 549,699 | |||||||||||
| Product Sales | 806,033 | 820,807 | 910,510 | ||||||||||||||
| Total Operating Revenues | 1,330,548 | 1,349,166 | 1,460,209 | ||||||||||||||
| Operating Expenses | |||||||||||||||||
| Electric Production Fuel | 60,945 | 60,339 | 65,110 | ||||||||||||||
| Electric Purchased Power | 61,561 | 78,292 | 100,281 | ||||||||||||||
| Electric Operating and Maintenance Expenses | 190,422 | 191,263 | 181,378 | ||||||||||||||
| Cost of Products Sold (excluding depreciation) | 434,522 | 454,122 | 542,944 | ||||||||||||||
| Nonelectric Selling, General, and Administrative Expenses | 80,065 | 72,663 | 69,718 | ||||||||||||||
| Depreciation and Amortization | 107,121 | 97,954 | 92,597 | ||||||||||||||
| Electric Property Taxes | 15,662 | 16,614 | 17,742 | ||||||||||||||
| Total Operating Expenses | 950,298 | 971,247 | 1,069,770 | ||||||||||||||
| Operating Income | 380,250 | 377,919 | 390,439 | ||||||||||||||
Other Income and (Expense) | |||||||||||||||||
| Interest Expense | (41,815) | (37,677) | (36,016) | ||||||||||||||
| Nonservice Cost Components of Postretirement Benefits | 9,609 | 10,597 | 1,075 | ||||||||||||||
| Other Income (Expense), net | 18,848 | 12,650 | 2,037 | ||||||||||||||
| Income Before Income Taxes | 366,892 | 363,489 | 357,535 | ||||||||||||||
| Income Tax Expense | 65,230 | 69,298 | 73,351 | ||||||||||||||
| Net Income | $ | 301,662 | $ | 294,191 | $ | 284,184 | |||||||||||
| Weighted-Average Common Shares Outstanding: | |||||||||||||||||
| Basic | 41,778 | 41,668 | 41,586 | ||||||||||||||
| Diluted | 42,072 | 42,039 | 41,931 | ||||||||||||||
| Earnings Per Share: | |||||||||||||||||
| Basic | $ | 7.22 | $ | 7.06 | $ | 6.83 | |||||||||||
| Diluted | $ | 7.17 | $ | 7.00 | $ | 6.78 | |||||||||||
See accompanying notes to consolidated financial statements.
50
OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
| Years Ended December 31, | |||||||||||||||||
| (in thousands) | 2024 | 2023 | 2022 | ||||||||||||||
| Net Income | $ | 301,662 | $ | 294,191 | $ | 284,184 | |||||||||||
| Other Comprehensive Income (Loss): | |||||||||||||||||
Unrealized Gain (Loss) on Available-for-Sale Securities, net of tax (expense) benefit of $(128), $(51) and $115 | 386 | 192 | (432) | ||||||||||||||
Unrealized Gain (Loss) on Pension and Other Postretirement Benefit Plans, net of tax (expense) benefit of $352, $(14) and $(2,769) | (1,002) | 41 | 7,871 | ||||||||||||||
Total Other Comprehensive Income (Loss) | (616) | 233 | 7,439 | ||||||||||||||
| Total Comprehensive Income | $ | 301,046 | $ | 294,424 | $ | 291,623 | |||||||||||
See accompanying notes to consolidated financial statements.
51
OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
| (in thousands, except common stock outstanding) | Common Stock Outstanding | Par Value, Common Stock | Additional Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total Shareholders' Equity | |||||||||||||||||||||||||||||
| Balance, December 31, 2021 | 41,551,524 | $ | 207,758 | $ | 419,760 | $ | 369,783 | $ | (6,524) | $ | 990,777 | ||||||||||||||||||||||||
| Employee Stock Purchase Plan Expenses | — | — | (219) | — | — | (219) | |||||||||||||||||||||||||||||
| Stock Issued Under Share-Based Compensation Plans, Net of Shares Withheld for Employee Taxes | 79,589 | 398 | (3,321) | — | — | (2,923) | |||||||||||||||||||||||||||||
| Stock Compensation Expense | — | — | 6,814 | — | — | 6,814 | |||||||||||||||||||||||||||||
| Net Income | — | — | — | 284,184 | — | 284,184 | |||||||||||||||||||||||||||||
| Other Comprehensive Income | — | — | — | — | 7,439 | 7,439 | |||||||||||||||||||||||||||||
Common Dividends ($1.65 per share) | — | — | — | (68,755) | — | (68,755) | |||||||||||||||||||||||||||||
| Balance, December 31, 2022 | 41,631,113 | $ | 208,156 | $ | 423,034 | $ | 585,212 | $ | 915 | $ | 1,217,317 | ||||||||||||||||||||||||
| Employee Stock Purchase Plan Expenses | — | — | (339) | — | — | (339) | |||||||||||||||||||||||||||||
| Stock Issued Under Share-Based Compensation Plans, Net of Shares Withheld for Employee Taxes | 79,408 | 397 | (3,485) | — | — | (3,088) | |||||||||||||||||||||||||||||
| Stock Compensation Expense | — | — | 7,753 | — | — | 7,753 | |||||||||||||||||||||||||||||
| Net Income | — | — | — | 294,191 | — | 294,191 | |||||||||||||||||||||||||||||
| Other Comprehensive Income | — | — | — | — | 233 | 233 | |||||||||||||||||||||||||||||
Common Dividends ($1.75 per share) | — | — | — | (73,061) | — | (73,061) | |||||||||||||||||||||||||||||
| Balance, December 31, 2023 | 41,710,521 | $ | 208,553 | $ | 426,963 | $ | 806,342 | $ | 1,148 | $ | 1,443,006 | ||||||||||||||||||||||||
| Employee Stock Purchase Plan Expenses | — | — | (359) | — | — | (359) | |||||||||||||||||||||||||||||
| Stock Issued Under Share-Based Compensation Plans, Net of Shares Withheld for Employee Taxes | 117,446 | 587 | (7,044) | — | — | (6,457) | |||||||||||||||||||||||||||||
| Stock Compensation Expense | — | — | 9,529 | — | — | 9,529 | |||||||||||||||||||||||||||||
| Net Income | — | — | — | 301,662 | — | 301,662 | |||||||||||||||||||||||||||||
Other Comprehensive Loss | — | — | — | — | (616) | (616) | |||||||||||||||||||||||||||||
Common Dividends ($1.87 per share) | — | — | — | (78,266) | — | (78,266) | |||||||||||||||||||||||||||||
| Balance, December 31, 2024 | 41,827,967 | $ | 209,140 | $ | 429,089 | $ | 1,029,738 | $ | 532 | $ | 1,668,499 | ||||||||||||||||||||||||
See accompanying notes to consolidated financial statements.
52
OTTER TAIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Years Ended December 31, | |||||||||||||||||
| (in thousands) | 2024 | 2023 | 2022 | ||||||||||||||
| Operating Activities | |||||||||||||||||
| Net Income | $ | 301,662 | $ | 294,191 | $ | 284,184 | |||||||||||
| Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: | |||||||||||||||||
| Depreciation and Amortization | 107,121 | 97,954 | 92,597 | ||||||||||||||
| Deferred Tax Credits | (182) | (744) | (745) | ||||||||||||||
| Deferred Income Taxes | 23,057 | 13,508 | 32,424 | ||||||||||||||
| Discretionary Contribution to Pension Plan | — | — | (20,000) | ||||||||||||||
| Investment (Gains) Losses | (5,482) | (7,222) | 3,296 | ||||||||||||||
| Stock Compensation Expense | 9,529 | 7,753 | 6,814 | ||||||||||||||
| Other, net | (3,111) | (423) | (1,473) | ||||||||||||||
| Changes in Operating Assets and Liabilities: | |||||||||||||||||
| Receivables | 11,179 | (12,750) | 30,560 | ||||||||||||||
| Inventories | 3,691 | (2,450) | 5,339 | ||||||||||||||
| Regulatory Assets | 5,194 | 12,479 | (2,464) | ||||||||||||||
| Other Assets | (11,640) | 2,817 | (368) | ||||||||||||||
| Accounts Payable | 14,826 | (9,988) | (29,763) | ||||||||||||||
| Accrued and Other Liabilities | (10,371) | 6 | (5,490) | ||||||||||||||
| Regulatory Liabilities | 16,821 | 20,973 | (6,846) | ||||||||||||||
| Pension and Other Postretirement Benefits | (9,563) | (11,605) | 1,244 | ||||||||||||||
| Net Cash Provided by Operating Activities | 452,731 | 404,499 | 389,309 | ||||||||||||||
| Investing Activities | |||||||||||||||||
| Capital Expenditures | (358,650) | (287,134) | (171,134) | ||||||||||||||
| Proceeds from Disposal of Noncurrent Assets | 8,849 | 6,225 | 4,346 | ||||||||||||||
| Purchases of Investments and Other Assets | (61,573) | (8,378) | (8,283) | ||||||||||||||
| Net Cash Used in Investing Activities | (411,374) | (289,287) | (175,071) | ||||||||||||||
| Financing Activities | |||||||||||||||||
Net (Repayments) Borrowings on Short-Term Debt | (11,807) | 73,218 | (82,959) | ||||||||||||||
| Proceeds from Issuance of Long-Term Debt | 120,000 | — | 90,000 | ||||||||||||||
| Payments for Retirement of Long-Term Debt | — | — | (30,000) | ||||||||||||||
| Dividends Paid | (78,266) | (73,061) | (68,755) | ||||||||||||||
| Payments for Shares Withheld for Employee Tax Obligations | (6,457) | (3,088) | (2,942) | ||||||||||||||
| Other, net | (549) | (904) | (2,123) | ||||||||||||||
Net Cash Provided by (Used in) Financing Activities | 22,921 | (3,835) | (96,779) | ||||||||||||||
| Net Change in Cash and Cash Equivalents | 64,278 | 111,377 | 117,459 | ||||||||||||||
| Cash and Cash Equivalents at Beginning of Period | 230,373 | 118,996 | 1,537 | ||||||||||||||
| Cash and Cash Equivalents at End of Period | $ | 294,651 | $ | 230,373 | $ | 118,996 | |||||||||||
| Supplemental Disclosures of Cash Flow Information | |||||||||||||||||
| Cash Paid During the Year for: | |||||||||||||||||
| Interest, net of amount capitalized | $ | 39,484 | $ | 36,956 | $ | 35,699 | |||||||||||
| Income Taxes | $ | 57,614 | $ | 46,284 | $ | 43,411 | |||||||||||
| Supplemental Disclosure of Noncash Investing Activities | |||||||||||||||||
| Accrued Property, Plant and Equipment Additions | $ | 20,281 | $ | 13,001 | $ | 12,420 | |||||||||||
See accompanying notes to consolidated financial statements
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OTTER TAIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Overview
Otter Tail Corporation (OTC) and its subsidiaries (collectively, the "Company," "us," "our" or "we") form a diverse, multi-platform business consisting of a vertically integrated, regulated utility with generation, transmission and distribution facilities complemented by manufacturing businesses providing metal fabrication for custom machine parts and metal components, manufacturing of extruded and thermoformed plastic products, and manufacturing of PVC pipe products. We classify our business into three segments: Electric, Manufacturing and Plastics. Note 2 includes an additional description of the segments and financial information regarding each segment.
Principles of Consolidation
These consolidated financial statements are presented in accordance with U.S. generally accepted accounting principles and include the accounts of OTC and its wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation except, as applicable, profits on sales to our regulated electric utility company from our nonregulated businesses, which is in accordance with the accounting requirements of regulated operations.
Use of Estimates
We use estimates based on the best information available in recording transactions and balances resulting from business operations. As better information becomes available or actual amounts are known, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
Regulatory Accounting
Our regulated electric utility company, OTP, is subject to regulation of rates and other matters by state utility commissions in Minnesota, North Dakota and South Dakota and by the FERC for certain interstate operations. OTP accounts for the financial effects of regulation in accordance with accounting guidance for regulated operations. This guidance allows for the recording of a regulatory asset for certain costs which otherwise would be recognized in the statements 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 statements of income or comprehensive income based on an expectation that the amount will be returned to customers in future rates. Amounts recorded as regulatory assets and regulatory liabilities are generally recognized in the statements of income at the time they are reflected in customer rates. In the event OTP ceases to meet the criteria to apply the guidance for regulated operations, the regulatory assets and liabilities that no longer meet such criteria would be removed from the consolidated balance sheets and included in the consolidated statements of income as an expense or income item, or in the consolidated statements of comprehensive income as a loss or gain item, in the period in which the application of this guidance ceases.
Cash Equivalents
We consider all highly liquid investments purchased with maturity dates of 90 days or less to be cash equivalents.
Concentration of Deposits
We hold deposits with financial institutions which potentially subject us to a concentration risk. These deposits are guaranteed by the Federal Deposit Insurance Corporation up to an insurance limit of $250,000. Currently, our cash deposits exceed federally insured levels.
Revenue from Contracts with Customers
Due to our diverse business operations, the recognition of revenue from contracts with customers depends on the product produced and sold or service performed. We recognize revenue from contracts with customers at prices that are fixed or determinable as evidenced by an agreement with the customer, when we have met our performance obligation under the contract and it is probable that we will collect the amount to which we are entitled in exchange for the goods or services transferred or to be transferred to the customer. Depending on the product produced and sold or service performed and the terms of the agreement with the customer, we recognize revenue either over time, in the case of delivery or transmission of electricity or related services or the production and storage of certain custom-made products, or at a point in time for the delivery of standardized products and other products made to customer specifications where the terms of the contract require transfer of the completed product. Provisions for sales returns, early payment discounts and volume-based variable pricing incentives are recorded as reductions to revenue at the time revenue is recognized based on customer history, historical information and current trends. We include revenues received for shipping and handling in operating revenues. Expenses paid for shipping and handling are recorded as part of cost of products sold. Sales or other taxes collected from customers are excluded from operating revenues.
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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 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 not yet billed to a customer, OTP records revenue and an unbilled receivable based on estimates of the amount of energy delivered and a composite rate per kwh consumed.
Manufacturing Segment Revenues. Our Manufacturing segment businesses earn revenue predominantly from the production and delivery of custom-made or standardized parts and products to customers across several industries and from the production and sale of tools and dies to other manufacturers. For the production and delivery of standardized products and other products made to customer specifications where the terms of the contract require transfer of the completed product, we have met our performance obligation and recognize revenue at the point in time when the product is shipped. At this point we have no further obligation to provide services related to such products. The shipping terms used in these transactions are free on board (FOB) shipping point.
Plastics Segment Revenues. Our Plastics segment businesses earn revenue predominantly from the sale and delivery of standardized PVC pipe products produced at their manufacturing facilities. Revenue from the sale of these products is recognized at the point in time when the product is shipped as there is no further obligation to provide services related to such products and the shipping terms are FOB shipping point. We have one customer within our Plastics segment for which we produce and store a product made to the customer’s specifications and design under a build and hold agreement. For sales to this customer, we recognize revenue as the custom-made product is produced, adjusting the amount of revenue for volume rebate variable pricing considerations we expect the customer will earn and applicable early payment discounts we expect the customer will take. Ownership of the pipe transfers to the customer prior to delivery and we are paid a negotiated fee for storage of the pipe. Revenue for storage of the pipe is recognized over time as the pipe is stored.
Alternative Revenue
In addition to recognizing revenue from contracts with customers, our Electric segment business also records revenue under alternative revenue program (ARP) requirements. Certain rate rider mechanisms qualify as ARP revenues as they provide for adjustments to rates outside of a general rate case proceeding to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. ARP riders generally provide for the recovery of specified costs and investments and include an incentive component to provide the regulated utility with a return on amounts invested.
We accrue ARP revenue on the basis of costs incurred, investments made and returns on those investments that qualify for recovery through established riders. ARP revenue is disclosed separately from revenue from contracts with customers and we have elected to report ARP revenue on a net basis, whereby amounts initially recorded as ARP revenue in a period are presented net of the reversal of amounts previously recognized as ARP revenue that are reclassified and recorded as revenue from contracts with customers when such amounts are included in the price of electricity to customers.
Receivables and Allowance for Credit Losses
We grant credit to our customers in the normal course of business with repayment terms generally ranging from 30 to 90 days after the invoice date. Late fees are assessed on certain receivables once they are 30 days past due. Unbilled receivables represent estimates of energy delivered to customers but not yet billed.
Receivables are stated at the billed or estimated unbilled amount less an allowance for estimated credit losses. An allowance for credit losses is established based on losses expected to occur over the contractual life of the receivable. We estimate an allowance for credit losses on our trade and unbilled receivables by evaluating historical aging and write-off history, adjusted for current and forecasted economic conditions, for groups of receivables that share similar economic characteristics. Other receivables are evaluated by reviewing individual accounts, considering aging, financial condition of the debtor, recent payment history and other relevant factors. Account balances are written off in the period they are deemed to be uncollectible.
Inventories
Inventories are valued at the lower of cost or net realizable value. Costs for fuel, material and supply inventories of our Electric segment are determined on an average cost basis. Costs for raw material, work in process and finished goods inventories of our Manufacturing and Plastics segments are determined on a first-in first-out (FIFO) basis.
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Inventories consist of the following as of December 31, 2024 and 2023:
| (in thousands) | 2024 | 2023 | |||||||||
| Finished Goods | $ | 43,345 | $ | 47,614 | |||||||
| Work in Process | 22,637 | 26,354 | |||||||||
| Raw Material, Fuel and Supplies | 82,903 | 75,733 | |||||||||
| Total Inventories | $ | 148,885 | $ | 149,701 | |||||||
Investments
We invest in and hold, through rabbi trusts, corporate-owned life insurance policies to provide future funding for obligations under our supplemental pension plan and a nonqualified deferred compensation plan. The polices are recorded at cash surrender value and there are no restrictions on our ability to surrender the policies.
We hold debt, mutual fund, and money market fund investments either as investments within our captive insurance entity, to provide future funding for obligations under nonqualified deferred compensation plans or provide a return on our available cash and liquidity. These investments are recorded at fair value. Debt securities are deemed to be available-for-sale securities, accordingly unrealized gains and losses are generally excluded from earnings and recognized in accumulated other comprehensive income. We evaluate whether declines in the fair value of debt securities below the cost basis are other-than-temporary. Declines in fair value deemed to be other-than-temporary result in the recognition of unrealized losses, or a portion thereof, in earnings. Unrealized gains and losses on mutual and money market funds are recognized in earnings immediately.
Property, Plant and Equipment
Electric plant is stated at original cost less accumulated depreciation. The cost of additions includes purchased assets, contracted work, direct labor and materials, allocable overheads and allowance for funds used during construction (AFUDC). The amount of interest capitalized to electric plant was $1.9 million in 2024, $1.9 million in 2023 and $0.9 million in 2022. Significant additions or improvements that extend an asset's useful life are capitalized, while repairs and maintenance costs are expensed as incurred.
Depreciation is recognized on a straight-line basis over the asset's estimated useful life. For certain asset classes, we employ a group or composite method of depreciation in which certain assets are combined and depreciated over the average life of the combined asset group. Actuarial studies are periodically performed to assess the remaining useful lives and salvage values of our assets, with any changes in these estimates incorporated into depreciation on a prospective basis. Gains or losses on group or composite asset dispositions are recorded to accumulated depreciation and impact current and future depreciation rates.
Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Removal costs, when incurred, are charged against the regulatory liability.
Property, plant and equipment of our nonelectric operations are carried at historical cost less accumulated depreciation. Depreciation is recognized on a straight-line basis over the asset's estimated useful life. The cost of additions includes purchased assets, contracted work, direct labor and materials, allocable overheads and capitalized interest, as applicable. No interest was capitalized in 2024, 2023 or 2022. Maintenance and repairs are expensed as incurred. Gains or losses on asset dispositions are included in the determination of operating income.
The estimated service lives for rate-regulated electric assets and nonelectric assets are included below:
| Service Life Range | |||||||||||
| (years) | Low | High | |||||||||
| Electric Assets: | |||||||||||
| Production Plant | 21 | 114 | |||||||||
| Transmission Plant | 51 | 80 | |||||||||
| Distribution Plant | 10 | 72 | |||||||||
| General Plant | 5 | 56 | |||||||||
| Nonelectric Assets: | |||||||||||
| Equipment | 2 | 20 | |||||||||
| Buildings and Leasehold Improvements | 2 | 40 | |||||||||
Jointly Owned Facilities
OTP is a joint owner in two coal-fired steam-powered electric generation plants: Big Stone Plant near Big Stone City, South Dakota and Coyote Station near Beulah, North Dakota. OTP is also a joint owner, with other regional utilities, in several 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
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of direct revenue and expenses are included in operating revenues and expenses in the consolidated statements of income. Each participant in the jointly owned facilities finances their own investments.
Goodwill and Other Intangible Assets
Goodwill is recognized and initially measured as any excess of the acquisition-date consideration transferred in a business combination over amounts recognized for the net identifiable assets acquired. Goodwill is not amortized, but is tested for impairment annually, or more frequently if an event occurs or circumstances change that would more likely than not result in an impairment of goodwill. Impairment testing is performed at the reporting unit level, which is defined as an operating segment or one level below an operating segment. We perform our impairment testing in the fourth quarter of each year and have identified three reporting units that carry a goodwill balance. We historically tested goodwill for impairment as of December 31st each year; however, in 2024, we elected to change the date of our annual goodwill impairment test to October 1st. We believe this new testing date allows us to better align our annual goodwill impairment testing procedures with our year-end financial reporting, as well as our annual budgeting and forecasting process. This change did not delay, accelerate or avoid the recognition of an impairment charge.
We perform a quantitative impairment assessment, electing to forgo the optional qualitative assessment. The quantitative assessment is a single-step test that identifies both the existence of impairment and the amount of impairment loss by comparing the estimated fair value of a reporting unit to its carrying value, with any excess carrying value over the fair value being recognized as an impairment loss.
Intangible assets with finite lives, which primarily consist of customer relationships, are carried at estimated fair value at the time of acquisition less accumulated amortization. The costs of the intangible assets are amortized over their estimated useful lives, which generally range from 15 to 20 years.
Cloud Computing Costs
We capitalize implementation costs incurred in cloud computing arrangements that are service contracts consistent with capitalized implementation costs incurred to develop or obtain internal-use software. Costs are amortized on a straight-line basis over the life of the associated contract. Capitalized implementation costs are amortized over periods up to ten years. Capitalized costs and related accumulated amortization are included in other noncurrent assets on the consolidated balance sheets. Below are the amounts of capitalized cost and related accumulated amortization as of December 31, 2024 and 2023:
| (in thousands) | 2024 | 2023 | |||||||||
| Cloud Computing Costs | $ | 15,741 | $ | 12,782 | |||||||
| Accumulated Amortization | (3,796) | (1,505) | |||||||||
| Cloud Computing Costs, net | $ | 11,945 | $ | 11,277 | |||||||
Amortization expense of capitalized implementation costs for each of the years ended December 31, 2024, 2023 and 2022 totaled $3.0 million, $1.3 million, and $1.4 million.
Leases
We recognize a right-of-use lease asset and a corresponding lease liability at the lease commencement date. The length of our lease agreements varies from less than one year to approximately ten years. We have elected to not record lease assets and liabilities for leases with a lease term at commencement of 12 months or less; such leases are expensed on a straight-line basis over the lease term. Certain of our leases contain options to renew or extend the lease term at our discretion if certain conditions are met. 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, or at such time when an event occurs which triggers the remeasurement of a lease, as applicable. In the determination of the lease term for one of our leased manufacturing facilities, we have incorporated the future lease renewals which we believe are reasonably certain to be exercised in the associated right-of-use asset and liability values.
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; such amounts are not incorporated into the measurement of the right-of-use lease asset or lease liability. 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 reference to market interest rates on long-term debt, incorporating considerations of the credit quality of the lessee and the term of lease.
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
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recoverable. We determine potential impairment by comparing the carrying amount of the assets with the net cash flows expected to be provided by operating activities of the business or related assets. If the sum of the expected future net cash flows is less than the carrying amount of the assets, an impairment loss would be recognized. Such an impairment loss would be measured as the amount by which the carrying amount exceeds the fair value of the asset.
Pension Plans and Other Postretirement Benefits
We maintain pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates. Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.
We have elected to apply a minimum amortization method for determining the amount of amortization of net cumulative gains or losses to be included as a component of net periodic benefit cost for any annual period. Cumulative gains and losses recognized in accumulated other comprehensive income or as a deferred regulatory asset or liability that are in excess of 10% of the projected benefit obligation or the market value of pension plan assets are amortized over the expected remaining future service period of active plan participants. In periods in which the cumulative gains and losses do not exceed 10%, no amortization to net period benefit cost is recognized.
Asset Retirement Obligations
Legal obligations related to the future retirement of long-lived assets are recognized as asset retirement obligations (ARO). An ARO is recognized in the period in which the legal obligation is incurred and the amount of the obligation can be reasonably estimated, with an offsetting increase to the associated long-lived asset. AROs are initially recognized at fair value and increased with the passage of time (accretion). ARO estimates are revised periodically with any adjustments reflected in the ARO and associated long-lived asset.
Income Taxes
We use the asset and liability method to account for income taxes. Under this method, deferred tax assets and liabilities are recognized for the expected future tax consequences of all temporary differences between the carrying amounts of assets and liabilities and their respective tax bases. Deferred taxes are recorded using the tax rates scheduled by tax law to be in effect in the periods when the temporary differences reverse. Deferred tax assets are reduced by a valuation allowance when it is more likely than not that a portion or all of the deferred tax assets will not be realized. The realizability of deferred tax assets is determined by taking into consideration forecasts of future taxable income, the reversal of other existing temporary differences, available net operating loss carryforwards and available tax planning strategies. Changes in valuation allowances are included in the provision for income taxes in the period of the changes.
We recognize the tax effects of all tax positions that are more-likely-than-not to be sustained on audit based solely on the technical merits of those positions as of the balance sheet date. Changes in the recognition or measurement of such positions are recognized in the provision for income taxes in the period of the changes. We classify interest and penalties on tax uncertainties as components of the provision for income taxes within the consolidated statements of income.
We have elected to account for transferable tax credits as a component of our income tax provision. We recognize the benefit of PTCs as a reduction of income tax expense in the period the credit is generated, which corresponds to the period the energy production occurs. We apply the deferral method of accounting for ITCs and state wind energy credits. Under this method, ITCs and state wind energy credits are amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit.
Deferred Compensation Plans
The Company sponsors two nonqualified deferred compensation plans for the benefit of executive officers and other select employees. Each plan allows participants to defer a specified amount or percentage of base wages or incentive compensation into the plan, subject to certain limitations. The Company, at its discretion, may make employer contributions to either plan during any annual period. Participant and employer deferred amounts are segregated into one or more accounts chosen by the participant. Participants earn a return on deferred amounts based on notional investments in the segregated accounts. Participants can elect lump sum distributions or annual installments of deferred balances during the participant's employment or upon retirement. As of December 31, 2024 and 2023, our liability to participants under these deferred compensation plans was $29.1 million and $24.6 million. Company contributions to these plans were $1.3 million, $1.2 million and $0.9 million for the years ended December 31, 2024, 2023 and 2022. Gains or (losses) recognized due to changes in our payment obligations in connection with these plans amounted to ($3.3 million), ($3.3 million) and $3.1 million for the years ended December 31, 2024, 2023 and 2022.
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
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time that a recipient is retirement eligible as determined under the award agreement. Awards granted to employees eligible for retirement on the date of grant are expensed in the period of grant. We recognize the effects of award forfeitures as they occur.
Fair Value Measurements
Fair value is defined as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants. Three levels of inputs may be used to measure fair value:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed on the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange.
Level 2 – Pricing inputs are other than quoted prices in active markets but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.
Level 3 – Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts.
In instances where the determination of the fair value measurement is based on inputs from different levels within the hierarchy, the level in the hierarchy within which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety.
Related Parties
The Otter Tail Corporation Foundation and Otter Tail Power Company Foundation are independent not-for-profit charitable entities affiliated with the Company and are not included in OTC's consolidated financial statements. Contribution obligations to the two foundations totaling $5.5 million and $5.5 million were recognized as of December 31, 2024 and 2023. Cash contributions paid to the two foundations during the years ended December 31, 2024, 2023 and 2022 were $5.5 million, $4.3 million, and $4.5 million.
Variable Interest Entity
In October 2012, the Coyote Station owners, including OTP, entered into an LSA with Coyote Creek Mining Company, LLC (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 upon profit and capital charge. CCMC was formed for the purpose of mining coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are required to buy certain assets of CCMC at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC because the Coyote Station owners are required to buy the membership interests of CCMC at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered the primary beneficiary of the VIE and the Company is not required to include CCMC in its consolidated financial statements.
If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and the Coyote Station owners purchase all of the outstanding membership interests of CCMC, the owners will satisfy or, if permitted by CCMC’s applicable lenders, assume all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. In the event the contract is terminated prior to the end of the term due to certain events, OTP’s maximum loss exposure, as a result of its involvement with CCMC, could be as high as $40 million, or OTP’s 35% share of CCMC’s unrecovered costs as of December 31, 2024, if recovery of such a loss is denied by regulatory authorities.
Recently Adopted Accounting Pronouncements
Segment Reporting. In November 2023, the Financial Accounting Standards Board (FASB) issued amended authoritative guidance codified in Accounting Standards Codification (ASC) 280, Segment Reporting. The amended guidance expands annual and interim disclosure requirements for reportable segments, primarily through expanded disclosures about significant segment expenses. We adopted this updated standard in the 2024 annual period on a retrospective basis, as required by the updated
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standard. The adoption of this updated standard resulted in additional disclosures related to our reportable segments and did not have an impact on our consolidated financial position or operating results.
Recent Accounting Pronouncements
Income Taxes. In December 2023, the FASB issued amended authoritative guidance codified in ASC 740, Income Taxes. The amended guidance requires additional disaggregated information in effective tax rate reconciliation disclosures and additional disaggregated information about income taxes paid. The updated standard is effective for our annual periods beginning in 2025. The amended guidance is to be applied on a prospective basis with the option to apply the standard retrospectively. We anticipate adopting the updated standard in our Form 10-K for the year ended December 31, 2025 and electing to apply the standard on a retrospective basis for all periods presented.
Disaggregated Income Statement Expenses. In November 2024, the FASB issued authoritative guidance codified in ASC 220, Income Statement—Reporting Comprehensive Income, which will require additional disclosure of certain costs and expenses within the notes to the financial statements. The updated standard is effective for our annual periods beginning in 2027 and interim periods beginning in the first quarter of fiscal 2028 and can be applied on either a prospective or retrospective basis. Early adoption is permitted. We are currently evaluating the impact that the updated standard will have on our financial statement disclosures.
2. Segment Information
Our business is comprised of three reportable segments, Electric, Manufacturing and Plastics, consistent with our business strategy, organizational structure and our internal reporting and review processes. Our chief operating decision maker (CODM) is our Chief Executive Officer. Segment net income is the sole measure of segment profit or loss used by our CODM in assessing segment performance and allocating resources to our segments. Our CODM uses segment net income in assessing financial performance on a monthly basis, reviewing and approving annual operating budgets and periodic forecasts, allocating capital or financial resources to our segments, making strategic decisions and measuring returns on equity in comparison to internal thresholds or peer entities.
The operations of our three reportable segments are further described below. We have aggregated two operating segments within our Manufacturing reportable segment based on the similarity between these businesses and their economic characteristics.
Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is a participant in the MISO markets. OTP’s operations have been our primary business since 1907.
Manufacturing consists of businesses in the following manufacturing activities: contract machining, metal parts stamping, fabrication and painting, and production of plastic thermoformed horticultural containers, life science and industrial packaging, and material handling components. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States.
Plastics consists of businesses producing PVC pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the western half of the United States and Canada.
Segment Profit or Loss
Information about each segment, including significant expenses and net income of each segment, for the years ended December 31, 2024, 2023 and 2022 are as follows:
Electric Segment
| (in thousands) | 2024 | 2023 | 2022 | ||||||||||||||
| Operating Revenue | $ | 524,515 | $ | 528,359 | $ | 549,699 | |||||||||||
| Production Fuel and Purchased Power | 122,506 | 138,631 | 165,391 | ||||||||||||||
| Operating and Maintenance Expenses | 190,422 | 191,263 | 181,378 | ||||||||||||||
| Depreciation and Amortization | 82,136 | 75,330 | 72,050 | ||||||||||||||
| Property Taxes | 15,662 | 16,614 | 17,742 | ||||||||||||||
| Interest Expense | 38,216 | 33,864 | 31,950 | ||||||||||||||
Income Tax Expense (Benefit) | (1,544) | 1,648 | 5,065 | ||||||||||||||
Other Segment Items(1) | (13,846) | (13,415) | (3,851) | ||||||||||||||
| Net Income | $ | 90,963 | $ | 84,424 | $ | 79,974 | |||||||||||
(1) Other segment items includes nonservice components of postretirement benefits, allowance for funds used during construction, and other expenses (income). | |||||||||||||||||
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Manufacturing Segment
| (in thousands) | 2024 | 2023 | 2022 | ||||||||||||||
| Operating Revenue | $ | 342,592 | $ | 402,781 | $ | 397,983 | |||||||||||
| Cost of Goods Sold | 283,390 | 324,245 | 327,228 | ||||||||||||||
| Selling, General, and Administrative Expenses | 40,110 | 49,396 | 41,690 | ||||||||||||||
| Interest Expense | 2,516 | 2,295 | 2,796 | ||||||||||||||
| Income Tax Expense | 2,895 | 5,390 | 5,321 | ||||||||||||||
| Other Segment Items | — | 1 | (2) | ||||||||||||||
| Net Income | $ | 13,681 | $ | 21,454 | $ | 20,950 | |||||||||||
Plastics Segment
| (in thousands) | 2024 | 2023 | 2022 | ||||||||||||||
| Operating Revenue | $ | 463,441 | $ | 418,026 | $ | 512,527 | |||||||||||
| Cost of Goods Sold | 166,628 | 143,521 | 227,571 | ||||||||||||||
| Selling, General, and Administrative Expenses | 24,908 | 20,103 | 20,378 | ||||||||||||||
| Interest Expense | 590 | 602 | 585 | ||||||||||||||
| Income Tax Expense | 70,644 | 66,066 | 68,688 | ||||||||||||||
| Other Segment Items | (76) | (14) | (69) | ||||||||||||||
| Net Income | $ | 200,747 | $ | 187,748 | $ | 195,374 | |||||||||||
Capital Expenditures and Identifiable Assets
The following provides capital expenditures for each reportable segment and our corporate cost center for the years ended December 31, 2024, 2023 and 2022:
| (in thousands) | 2024 | 2023 | 2022 | ||||||||||||||
| Capital Expenditures | |||||||||||||||||
| Electric | 301,454 | 240,695 | 147,869 | ||||||||||||||
| Manufacturing | 32,159 | 23,284 | 17,954 | ||||||||||||||
| Plastics | 24,749 | 23,029 | 5,245 | ||||||||||||||
| Corporate | 288 | 126 | 66 | ||||||||||||||
Total | $ | 358,650 | $ | 287,134 | $ | 171,134 | |||||||||||
The following provides the identifiable assets by segment and corporate assets as of December 31, 2024 and 2023:
| (in thousands) | 2024 | 2023 | |||||||||
| Identifiable Assets | |||||||||||
| Electric | $ | 2,785,522 | $ | 2,533,831 | |||||||
| Manufacturing | 254,445 | 251,343 | |||||||||
| Plastics | 186,043 | 164,179 | |||||||||
| Corporate | 426,072 | 293,215 | |||||||||
Total | $ | 3,652,082 | $ | 3,242,568 | |||||||
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Reconciliation to Consolidated Amounts
Certain 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 is not an operating segment, rather it is added to operating segment totals to reconcile to consolidated amounts.
Included below is a reconciliation of certain segment information and our unallocated corporate costs to consolidated amounts for the years ended December 31, 2024, 2023 and 2022:
| (in thousands) | 2024 | 2023 | 2022 | ||||||||||||||
| Depreciation and Amortization | |||||||||||||||||
| Electric | $ | 82,136 | $ | 75,330 | $ | 72,050 | |||||||||||
| Manufacturing | 20,393 | 18,495 | 16,202 | ||||||||||||||
| Plastics | 4,494 | 4,027 | 4,205 | ||||||||||||||
| Corporate | 98 | 102 | 140 | ||||||||||||||
Total | 107,121 | 97,954 | 92,597 | ||||||||||||||
| Interest Expense | |||||||||||||||||
| Total Interest Expense of Reportable Segments | 41,322 | 36,761 | 35,331 | ||||||||||||||
| Corporate Interest Expense | 493 | 916 | 685 | ||||||||||||||
Total | 41,815 | 37,677 | 36,016 | ||||||||||||||
| Income Tax Expense (Benefit) | |||||||||||||||||
| Total Income Tax Expense of Reportable Segments | 71,995 | 73,104 | 79,074 | ||||||||||||||
| Corporate Income Tax Benefit | (6,765) | (3,806) | (5,723) | ||||||||||||||
Total | 65,230 | 69,298 | 73,351 | ||||||||||||||
| Net Income (Loss) | |||||||||||||||||
| Total Net Income of Reportable Segments | 305,391 | 293,626 | 296,298 | ||||||||||||||
| Corporate Net Income (Loss) | (3,729) | 565 | (12,114) | ||||||||||||||
Total | 301,662 | 294,191 | 284,184 | ||||||||||||||
Concentrations
Our Plastics segment businesses use PVC resin as a critical component within their PVC pipe manufacturing process. There are a limited number of PVC resin suppliers in the U.S., and in 2024 we sourced all of our PVC resin needs from four vendors. Although there are a limited number of PVC resin suppliers, we believe that other suppliers could provide PVC resin on comparable terms. Additionally, most U.S. resin production plants are located in the Gulf Coast region. These plants are subject to the risk of damage and production shutdowns because of exposure to hurricanes or other extreme weather events that occur in this region. The loss of a key vendor, or any interruption or delay in the supply of PVC resin could cause production delays, a possible loss of sales or result in increased costs to secure resin, all of which would adversely affect our operating results.
For the year ended December 31, 2024, two customers combined accounted for 19% of Electric segment operating revenues, two customers combined to account for 36% of Manufacturing segment operating revenues and two customers combined to account for 52% of Plastics segment operating revenues, with one of those customers providing 11% of our consolidated operating revenues.
Entity-Wide Information
All of our long-lived assets are located within the United States and substantially all of our operating revenues are from customers located within the United States.
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3. Revenue
We present our operating revenues from external customers, in total and by amounts arising from contracts with customers and ARP arrangements, disaggregated by revenue source and segment for the years ended December 31, 2024, 2023 and 2022:
| (in thousands) | 2024 | 2023 | 2022 | ||||||||||||||
| Operating Revenues | |||||||||||||||||
| Electric Segment | |||||||||||||||||
| Retail: Residential | $ | 133,408 | $ | 135,570 | $ | 143,888 | |||||||||||
| Retail: Commercial and Industrial | 311,968 | 312,551 | 318,494 | ||||||||||||||
| Retail: Other | 7,838 | 7,719 | 7,918 | ||||||||||||||
| Total Retail | 453,214 | 455,840 | 470,300 | ||||||||||||||
| Transmission | 53,517 | 52,555 | 52,213 | ||||||||||||||
| Wholesale | 11,077 | 12,459 | 18,539 | ||||||||||||||
| Other | 6,707 | 7,505 | 8,647 | ||||||||||||||
| Total Electric Segment | 524,515 | 528,359 | 549,699 | ||||||||||||||
| Manufacturing Segment | |||||||||||||||||
| Metal Parts and Tooling | 303,077 | 351,267 | 338,865 | ||||||||||||||
| Plastic Products and Tooling | 32,210 | 41,395 | 49,080 | ||||||||||||||
| Scrap Metal | 7,305 | 10,119 | 10,038 | ||||||||||||||
| Total Manufacturing Segment | 342,592 | 402,781 | 397,983 | ||||||||||||||
| Plastics Segment | |||||||||||||||||
| PVC Pipe | 463,441 | 418,026 | 512,527 | ||||||||||||||
| Total Operating Revenue | 1,330,548 | 1,349,166 | 1,460,209 | ||||||||||||||
| Less: Noncontract Revenues Included Above | |||||||||||||||||
| Electric Segment - ARP Revenues | 575 | (4,310) | (9,266) | ||||||||||||||
| Total Operating Revenues from Contracts with Customers | $ | 1,329,973 | $ | 1,353,476 | $ | 1,469,475 | |||||||||||
4. Receivables
Receivables as of December 31, 2024 and 2023 are as follows:
| (in thousands) | 2024 | 2023 | |||||||||
| Receivables | |||||||||||
| Trade | $ | 112,169 | $ | 129,257 | |||||||
| Other | 13,799 | 9,084 | |||||||||
| Unbilled Receivables | 21,916 | 21,324 | |||||||||
| Total Receivables | 147,884 | 159,665 | |||||||||
| Less Allowance for Credit Losses | 1,920 | 2,522 | |||||||||
| Receivables, net of allowance for credit losses | $ | 145,964 | $ | 157,143 | |||||||
The following is a summary of activity in the allowance for credit losses for the years ended December 31, 2024 and 2023:
| (in thousands) | 2024 | 2023 | |||||||||
| Beginning Balance | $ | 2,522 | $ | 1,648 | |||||||
| Additions Charged to Expense | 1,242 | 2,014 | |||||||||
| Reductions for Amounts Written Off, Net of Recoveries | (1,844) | (1,140) | |||||||||
| Ending Balance | $ | 1,920 | $ | 2,522 | |||||||
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5. Investments
The following is a summary of our investments as of December 31, 2024 and 2023:
| (in thousands) | 2024 | 2023 | |||||||||
| Short-term Investments | |||||||||||
Government Debt Securities | $ | 753 | $ | — | |||||||
| Long-term Investments | |||||||||||
| Corporate-Owned Life Insurance Policies | 47,895 | 42,287 | |||||||||
Government Debt Securities | 60,378 | 7,724 | |||||||||
Corporate Debt Securities | 1,628 | 1,579 | |||||||||
| Mutual Funds | 10,653 | 7,771 | |||||||||
| Money Market Funds | 596 | 3,125 | |||||||||
| Other Investments | 27 | 30 | |||||||||
| Total Long-term Investments | 121,177 | 62,516 | |||||||||
| Total Investments | $ | 121,930 | $ | 62,516 | |||||||
In April 2024, we made a $50.1 million investment in U.S. treasuries which mature in September 2026. As of December 31, 2024, our government and corporate debt securities had maturity dates ranging from May 2025 to August 2029. During the years ended December 31, 2024 and 2023, our investment income, which consisted primarily of interest on our cash equivalent and debt security investments and gains on our corporate-owned life insurance policy investments, totaled $19.8 million and $15.2 million, which is included in other income in our consolidated statements of income.
Debt Securities
The following table summarizes the amortized cost and fair value of debt securities available for sale and the corresponding amounts of gross unrealized gains and losses as of December 31, 2024:
| December 31, 2024 | |||||||||||||||||||||||
| (in thousands) | Amortized Cost | Gross Unrealized Gains | Gross Unrealized (Losses) | Fair Value | |||||||||||||||||||
| Government Debt Securities | $ | 60,891 | $ | 424 | $ | (184) | $ | 61,131 | |||||||||||||||
| Corporate Debt Securities | 1,629 | 9 | (10) | 1,628 | |||||||||||||||||||
| Total | $ | 62,520 | $ | 433 | $ | (194) | $ | 62,759 | |||||||||||||||
Unrealized gains and losses on available-for-sale debt securities as of December 31, 2023 were not material. As of December 31, 2024 and December 31, 2023, no unrealized losses on debt securities were deemed to be other-than-temporary.
The following table summarizes the fair value of debt securities available for sale by contractual maturity date as of December 31, 2024:
| (in thousands) | December 31, 2024 | ||||
Due in one year or less | $ | 753 | |||
Due in one to five years | 62,006 | ||||
| Total | $ | 62,759 | |||
Equity Securities
The amount of net unrealized gains and losses during the years ended December 31, 2024 and 2023 on marketable equity securities still held as of December 31, 2024 and 2023, respectively, was not material.
6. Regulatory Matters
Regulatory Assets and Liabilities
The following presents our current and long-term regulatory assets and liabilities as of December 31, 2024 and 2023 and the period we expect to recover or refund such amounts:
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| Period of | 2024 | 2023 | |||||||||||||||||||||||||||
| (in thousands) | Recovery/Refund | Current | Long-Term | Current | Long-Term | ||||||||||||||||||||||||
| Regulatory Assets | |||||||||||||||||||||||||||||
Pension and Other Postretirement Benefit Plans1 | See below | $ | — | $ | 88,161 | $ | 154 | $ | 86,134 | ||||||||||||||||||||
Alternative Revenue Program Riders2 | Up to 2 years | 4,257 | 195 | 3,719 | 158 | ||||||||||||||||||||||||
| Deferred Income Taxes | Asset lives | — | 8,944 | — | 6,940 | ||||||||||||||||||||||||
Fuel Clause Adjustments1 | Up to 1 year | 2,218 | — | 7,294 | — | ||||||||||||||||||||||||
Derivative Instruments1 | Up to 1 year | 1,989 | — | 4,210 | — | ||||||||||||||||||||||||
Other1 | Various | 1,498 | 1,373 | 750 | 2,483 | ||||||||||||||||||||||||
| Total Regulatory Assets | 9,962 | 98,673 | 16,127 | 95,715 | |||||||||||||||||||||||||
| Regulatory Liabilities | |||||||||||||||||||||||||||||
| Deferred Income Taxes | Asset lives | — | 130,387 | — | 136,022 | ||||||||||||||||||||||||
| Plant Removal Obligations | Asset lives | — | 126,263 | — | 117,030 | ||||||||||||||||||||||||
| Fuel Clause Adjustments | Up to 1 year | 11,432 | — | 11,350 | — | ||||||||||||||||||||||||
| Alternative Revenue Program Riders | Up to 1 year | 14,255 | — | 6,885 | — | ||||||||||||||||||||||||
| North Dakota PTC Refunds | Asset lives | — | 20,099 | — | 12,011 | ||||||||||||||||||||||||
| Pension and Other Postretirement Benefit Plans | See below | 2,547 | 10,758 | 6,138 | 11,307 | ||||||||||||||||||||||||
| Other | Various | 1,073 | 1,421 | 1,035 | 177 | ||||||||||||||||||||||||
| Total Regulatory Liabilities | $ | 29,307 | $ | 288,928 | $ | 25,408 | $ | 276,547 | |||||||||||||||||||||
1Costs subject to recovery without a rate of return. | |||||||||||||||||||||||||||||
2Amount eligible for recovery includes an incentive or rate of return. | |||||||||||||||||||||||||||||
Pension and Other Postretirement Benefit Plans represent benefit costs and actuarial losses and gains subject to recovery or refund through rates as they are expensed or amortized. These unrecognized benefit costs and actuarial losses and gains are eligible for treatment as regulatory assets or liabilities based on their probable inclusion in future electric rates.
Alternative Revenue Program Riders regulatory assets and liabilities are revenues not yet collected from customers or amounts collected from customers that are subject to refund, respectively, primarily due to investments in qualifying transmission, conservation, renewable resource, environmental and other generation assets, and the impact of decoupling.
Deferred Income Taxes primarily represent the revaluation of accumulated deferred income taxes arising from the change in the federal income tax rate in 2017. This amount is being refunded to customers over the estimated lives of the property assets from which the deferred income taxes originated.
Fuel Clause Adjustments represent the under- or over-collection of fuel costs relative to the estimated cost of fuel included in customer rates, which will be collected from or returned to customers in future periods.
Derivative Instruments represent unrealized losses recognized on derivative instruments. On final settlement of such instruments, any realized losses are recovered from customers.
Plant Removal Obligations represent amounts collected from customers to be used to cover actual removal costs as incurred.
North Dakota PTC Refunds represent PTCs earned from our wind energy facilities. These amounts are being allocated to customers over the lives of the assets generating the credits.
Other regulatory assets and liabilities include other amounts that we expect to recover from, or return to, customers in future periods, such as the cost of abandoned projects, costs incurred in connection with recent rate cases and other items.
North Dakota Rate Case
On November 2, 2023, OTP filed a request with the NDPSC for an increase in revenue recoverable under general rates in North Dakota. In its filing, OTP requested a net increase in annual revenue of $17.4 million, or 8.4%, based on an allowed rate of return on rate base of 7.85% and an allowed rate of ROE of 10.6% on an equity ratio of 53.5% of total capital. The filing also included an interim rate request of a net increase in annual revenue of $12.4 million, or 6.0%, which was approved by the NDPSC on December 13, 2023. Interim rates went into effect on January 1, 2024. On July 3, 2024, OTP filed an update to the original request increasing the amount of the net annual revenue requirement from $17.4 million to $22.5 million, or a net increase of 10.9% in annual revenue, to account for certain items identified throughout the regulatory process.
On December 30, 2024, the NDPSC approved a settlement agreement between OTP and certain interested parties in the general rate case and issued its written order on final rates. The key provisions of the order include a revenue requirement of $225.6 million, based on a return on rate base of 7.53%, and an allowed ROE of 10.10% on an equity ratio of 53.5%. The net annual revenue requirement includes a net increase of $13.1 million, or 6.18%. OTP’s revenue requirement was reduced by approximately
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$3.0 million primarily due to the inclusion of forecasted PTCs plus adjustments for new customer load additions, which were not included in OTP’s updated request filed on July 3, 2024. Through the settlement of the case, the parties also agreed to establish an earnings sharing mechanism, whereby 70% of actual earnings in excess of a 10.20% ROE would be returned to customers, with OTP retaining the remaining 30%.
7. Property, Plant and Equipment
Major classes of property, plant and equipment as of December 31, 2024 and 2023 include:
| (in thousands) | 2024 | 2023 | |||||||||
| Electric Plant in Service | |||||||||||
| Production | $ | 1,469,008 | $ | 1,412,826 | |||||||
| Transmission | 820,415 | 777,613 | |||||||||
| Distribution | 726,159 | 654,704 | |||||||||
| General | 165,361 | 144,738 | |||||||||
| Electric Plant in Service | 3,180,943 | 2,989,881 | |||||||||
| Construction Work in Progress | 231,890 | 137,212 | |||||||||
| Total Gross Electric Plant | 3,412,833 | 3,127,093 | |||||||||
Less Accumulated Depreciation | 899,049 | 851,148 | |||||||||
| Net Electric Plant | 2,513,784 | 2,275,945 | |||||||||
| Nonelectric Property, Plant and Equipment | |||||||||||
| Equipment | 260,307 | 233,571 | |||||||||
| Buildings and Leasehold Improvements | 88,680 | 64,753 | |||||||||
| Land | 13,578 | 13,600 | |||||||||
| Nonelectric Property, Plant and Equipment | 362,565 | 311,924 | |||||||||
| Construction Work in Progress | 40,536 | 38,062 | |||||||||
| Total Gross Nonelectric Property, Plant and Equipment | 403,101 | 349,986 | |||||||||
Less Accumulated Depreciation | 224,425 | 207,556 | |||||||||
| Net Nonelectric Property, Plant and Equipment | 178,676 | 142,430 | |||||||||
| Net Property, Plant and Equipment | $ | 2,692,460 | $ | 2,418,375 | |||||||
Depreciation expense for the years ended December 31, 2024, 2023 and 2022 totaled $99.4 million, $90.8 million and $84.4 million.
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The following table provides OTP’s ownership percentages and amounts included in the December 31, 2024 and 2023 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, 2024 | |||||||||||||||||||||||||||||
| Big Stone Plant | 53.9 | % | $ | 345,990 | $ | 459 | $ | (135,065) | $ | 211,384 | |||||||||||||||||||
| Coyote Station | 35.0 | % | 188,066 | 813 | (118,268) | 70,611 | |||||||||||||||||||||||
| Big Stone South–Ellendale 345 kV line | 50.0 | % | 106,185 | — | (8,445) | 97,740 | |||||||||||||||||||||||
| Fargo–Monticello 345 kV line | 14.2 | % | 78,184 | — | (12,247) | 65,937 | |||||||||||||||||||||||
| Big Stone South–Brookings 345 kV line | 50.0 | % | 53,167 | — | (5,822) | 47,345 | |||||||||||||||||||||||
| Brookings–Southeast Twin Cities 345 kV line | 4.8 | % | 28,013 | 1,131 | (3,941) | 25,203 | |||||||||||||||||||||||
| Bemidji–Grand Rapids 230 kV line | 14.8 | % | 16,331 | — | (3,693) | 12,638 | |||||||||||||||||||||||
| Jamestown– Ellendale 345 kV line | 50.0 | % | — | 5,509 | — | 5,509 | |||||||||||||||||||||||
| Big Stone South–Alexandria 345 kV line | 40.0 | % | — | 2,418 | — | 2,418 | |||||||||||||||||||||||
| Alexandria–Big Oaks 345 kV line | 14.2 | % | — | 417 | — | 417 | |||||||||||||||||||||||
| Oslo - Lake Ardoch 115 kV line | 72.0 | % | — | 2,646 | — | 2,646 | |||||||||||||||||||||||
| December 31, 2023 | |||||||||||||||||||||||||||||
| Big Stone Plant | 53.9 | % | $ | 341,683 | $ | 820 | $ | (126,904) | $ | 215,599 | |||||||||||||||||||
| Coyote Station | 35.0 | % | 188,656 | 104 | (115,306) | 73,454 | |||||||||||||||||||||||
| Big Stone South–Ellendale 345 kV line | 50.0 | % | 106,185 | — | (7,181) | 99,004 | |||||||||||||||||||||||
| Fargo–Monticello 345 kV line | 14.2 | % | 78,184 | — | (11,238) | 66,946 | |||||||||||||||||||||||
| Big Stone South–Brookings 345 kV line | 50.0 | % | 53,170 | — | (5,207) | 47,963 | |||||||||||||||||||||||
| Brookings–Southeast Twin Cities 345 kV line | 4.8 | % | 26,409 | 83 | (3,617) | 22,875 | |||||||||||||||||||||||
| Bemidji–Grand Rapids 230 kV line | 14.8 | % | 16,331 | — | (3,568) | 12,763 | |||||||||||||||||||||||
Jamestown–Ellendale 345 kV line | 50.0 | % | — | 1,121 | — | 1,121 | |||||||||||||||||||||||
| Big Stone South–Alexandria 345 kV line | 40.0 | % | — | 555 | — | 555 | |||||||||||||||||||||||
| Alexandria–Big Oaks 345 kV line | 14.2 | % | — | 343 | — | 343 | |||||||||||||||||||||||
8. Intangible Assets
The following table summarizes our goodwill by segment as of December 31, 2024 and 2023:
| (in thousands) | 2024 | 2023 | |||||||||
| 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 2024 and 2023, indicated no impairment existed as of the test date.
The following table summarizes the components of our intangible assets as of December 31, 2024 and 2023:
| (in thousands) | Gross Amount | Accumulated Amortization | Net Carrying Amount | ||||||||||||||
| December 31, 2024 | |||||||||||||||||
| Customer Relationships | $ | 22,491 | $ | 16,766 | $ | 5,725 | |||||||||||
| Other | 26 | 8 | 18 | ||||||||||||||
| Total | $ | 22,517 | $ | 16,774 | $ | 5,743 | |||||||||||
| December 31, 2023 | |||||||||||||||||
| Customer Relationships | $ | 22,491 | $ | 15,667 | $ | 6,824 | |||||||||||
| Other | 26 | 7 | 19 | ||||||||||||||
| Total | $ | 22,517 | $ | 15,674 | $ | 6,843 | |||||||||||
Amortization expense for these intangible assets for each of the years ended December 31, 2024, 2023 and 2022 totaled $1.1 million.
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Annual amortization expense for these intangible assets for the next five years is:
| (in thousands) | 2025 | 2026 | 2027 | 2028 | 2029 | ||||||||||||||||||||||||
| Amortization Expense | $ | 1,100 | $ | 1,092 | $ | 1,090 | $ | 554 | $ | 285 | |||||||||||||||||||
9. Leases
We lease rail cars, warehouse and office space, land, and certain office, manufacturing, material handling and other equipment under varying terms and conditions. All leases are classified as operating leases.
The components of lease cost and lease cash flows for the years ended December 31, 2024, 2023, and 2022 are as follows:
| (in thousands) | 2024 | 2023 | 2022 | ||||||||||||||
| Lease Cost | |||||||||||||||||
| Operating Lease Cost | $ | 6,688 | $ | 6,309 | $ | 5,606 | |||||||||||
| Variable Lease Cost | 1,460 | 1,433 | 1,386 | ||||||||||||||
| Short-Term Lease Cost | 2,746 | 2,525 | 1,517 | ||||||||||||||
| Total Lease Cost | $ | 10,894 | $ | 10,267 | $ | 8,509 | |||||||||||
| Lease Cash Flows | |||||||||||||||||
| Operating Cash Flows from Operating Leases | $ | 6,762 | $ | 6,424 | $ | 5,592 | |||||||||||
A summary of operating lease right-of-use lease assets and lease liabilities as of December 31, 2024 and 2023 is as follows:
| (in thousands) | 2024 | 2023 | ||||||||||||
Right of Use Lease Assets1 | $ | 28,179 | $ | 16,788 | ||||||||||
| Lease Liabilities | ||||||||||||||
Current2 | 4,776 | 5,756 | ||||||||||||
Long-Term3 | 23,567 | 11,258 | ||||||||||||
| Total Lease Liabilities | $ | 28,343 | $ | 17,014 | ||||||||||
Operating lease assets obtained in exchange for new operating lease liabilities amounted to $17.6 million and $3.6 million for the years ended December 31, 2024 and 2023.
Maturities of lease liabilities as of December 31, 2024 for each of the next five years and in the aggregate thereafter are as follows:
| (in thousands) | Operating Leases | ||||
| 2025 | $ | 6,350 | |||
| 2026 | 5,638 | ||||
| 2027 | 4,785 | ||||
| 2028 | 3,604 | ||||
| 2029 | 2,750 | ||||
| Thereafter | 12,921 | ||||
| Total Lease Payments | 36,048 | ||||
| Less: Interest | 7,705 | ||||
| Present Value of Lease Liabilities | $ | 28,343 | |||
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The weighted-average remaining lease term and the weighted-average discount rate as of December 31, 2024 and 2023 are as follows:
| 2024 | 2023 | ||||||||||
| Weighted-Average Remaining Lease Term (in years) | 7.9 | 3.4 | |||||||||
| Weighted-Average Discount Rate | 6.37 | % | 5.40 | % | |||||||
10. Short-Term and Long-Term Borrowings
The following is a summary of our outstanding short- and long-term borrowings by borrower, OTC or OTP, as of December 31, 2024 and 2023:
| 2024 | 2023 | ||||||||||||||||||||||||||||||||||
| (in thousands) | OTC | OTP | Total | OTC | OTP | Total | |||||||||||||||||||||||||||||
| Short-Term Debt | $ | — | $ | 69,615 | $ | 69,615 | $ | — | $ | 81,422 | $ | 81,422 | |||||||||||||||||||||||
| Long-Term Debt | 79,900 | 863,834 | 943,734 | 79,849 | 744,210 | 824,059 | |||||||||||||||||||||||||||||
| Total | $ | 79,900 | $ | 933,449 | $ | 1,013,349 | $ | 79,849 | $ | 825,632 | $ | 905,481 | |||||||||||||||||||||||
Short-Term Debt
The following is a summary of our lines of credit as of December 31, 2024 and 2023:
| 2024 | 2023 | ||||||||||||||||||||||||||||
| (in thousands) | Line Limit | Amount Outstanding | Letters of Credit | Amount Available | Amount Available | ||||||||||||||||||||||||
| OTC Credit Agreement | $ | 170,000 | $ | — | $ | — | $ | 170,000 | $ | 170,000 | |||||||||||||||||||
| OTP Credit Agreement | 220,000 | 69,615 | 8,772 | 141,613 | 79,446 | ||||||||||||||||||||||||
| Total | $ | 390,000 | $ | 69,615 | $ | 8,772 | $ | 311,613 | $ | 249,446 | |||||||||||||||||||
On December 11, 2024, OTC entered into a Sixth Amended and Restated Credit Agreement (the OTC Credit Agreement) and OTP entered into a Fifth Amended and Restated Credit Agreement (the OTP Credit Agreement), in each case amending and restating the previously existing credit agreements, to extend the maturity date of each credit facility and adjust the maximum debt to total capitalization covenant. The OTP Credit Agreement was also amended to increase the maximum borrowing capacity. The OTC agreement provides for a $170.0 million unsecured revolving line of credit and the OTP agreement provides for a $220.0 million unsecured revolving line of credit to support operations, fund capital expenditures, refinance certain indebtedness and provide for the issuance of letters of credit in an aggregate amount not to exceed $40.0 million under the OTC Credit Agreement and $50.0 million under the OTP Credit Agreement. Each credit facility includes an accordion provision allowing the borrower to increase the borrowing capacity under the facility, subject to certain conditions, up to $290.0 million and $300.0 million under the OTC Credit Agreement and OTP Credit Agreement, respectively.
Borrowings under each credit facility are subject to a variable rate of interest on outstanding balances and a commitment fee is charged based on the average unused amount available to be drawn under the respective facility. The variable rate of interest to be charged is based on a benchmark interest rate, either SOFR or a Base Rate, as defined in the credit agreements, selected by the borrower at the time of an advance, subject to the conditions of each agreement, plus an applicable credit spread. The credit spread ranges from zero to 2.00%, depending on the benchmark interest rate selected, and is subject to adjustment based on the credit ratings of the relevant borrower. The weighted-average interest rate on all outstanding borrowings as of December 31, 2024 and 2023 was 5.61% and 6.70%.
Each credit facility contains a number of restrictions on the borrower, including restrictions on the ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party and engage in transactions with related parties. The agreements also require the borrower to maintain various financial covenants, as further described below. Each credit facility includes a cross-default provision whereby an event of default of other outstanding indebtedness will trigger an event of default under the agreement. Each credit facility expires on December 11, 2029.
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Long-Term Debt
The following is a summary of outstanding long-term debt by borrower as of December 31, 2024 and 2023:
| (in thousands) | ||||||||||||||||||||||||||||||||
| Entity | Debt Instrument | Rate | Maturity | 2024 | 2023 | |||||||||||||||||||||||||||
| OTC | Guaranteed Senior Notes | 3.55% | 12/15/26 | $ | 80,000 | $ | 80,000 | |||||||||||||||||||||||||
| OTP | Series 2007C Senior Unsecured Notes | 6.37% | 08/02/27 | 42,000 | 42,000 | |||||||||||||||||||||||||||
| OTP | Series 2013A Senior Unsecured Notes | 4.68% | 02/27/29 | 60,000 | 60,000 | |||||||||||||||||||||||||||
| OTP | Series 2019A Senior Unsecured Notes | 3.07% | 10/10/29 | 10,000 | 10,000 | |||||||||||||||||||||||||||
| OTP | Series 2020A Senior Unsecured Notes | 3.22% | 02/25/30 | 10,000 | 10,000 | |||||||||||||||||||||||||||
| OTP | Series 2020B Senior Unsecured Notes | 3.22% | 08/20/30 | 40,000 | 40,000 | |||||||||||||||||||||||||||
| OTP | Series 2021A Senior Unsecured Notes | 2.74% | 11/29/31 | 40,000 | 40,000 | |||||||||||||||||||||||||||
| OTP | Series 2024A Senior Unsecured Notes | 5.48% | 04/01/34 | 60,000 | — | |||||||||||||||||||||||||||
| OTP | Series 2007D Senior Unsecured Notes | 6.47% | 08/20/37 | 50,000 | 50,000 | |||||||||||||||||||||||||||
| OTP | Series 2019B Senior Unsecured Notes | 3.52% | 10/10/39 | 26,000 | 26,000 | |||||||||||||||||||||||||||
| OTP | Series 2020C Senior Unsecured Notes | 3.62% | 02/25/40 | 10,000 | 10,000 | |||||||||||||||||||||||||||
| OTP | Series 2013B Senior Unsecured Notes | 5.47% | 02/27/44 | 90,000 | 90,000 | |||||||||||||||||||||||||||
| OTP | Series 2018A Senior Unsecured Notes | 4.07% | 02/07/48 | 100,000 | 100,000 | |||||||||||||||||||||||||||
| OTP | Series 2019C Senior Unsecured Notes | 3.82% | 10/10/49 | 64,000 | 64,000 | |||||||||||||||||||||||||||
| OTP | Series 2020D Senior Unsecured Notes | 3.92% | 02/25/50 | 15,000 | 15,000 | |||||||||||||||||||||||||||
| OTP | Series 2021B Senior Unsecured Notes | 3.69% | 11/29/51 | 100,000 | 100,000 | |||||||||||||||||||||||||||
| OTP | Series 2022A Senior Unsecured Notes | 3.77% | 05/20/52 | 90,000 | 90,000 | |||||||||||||||||||||||||||
| OTP | Series 2024B Senior Unsecured Notes | 5.77% | 04/01/54 | 60,000 | — | |||||||||||||||||||||||||||
| Total | 947,000 | 827,000 | ||||||||||||||||||||||||||||||
| Less: | Unamortized Long-Term Debt Issuance Costs | 3,266 | 2,941 | |||||||||||||||||||||||||||||
| Total Long-Term Debt Net of Unamortized Debt Issuance Costs | $ | 943,734 | $ | 824,059 | ||||||||||||||||||||||||||||
On March 28, 2024, OTP entered into a Note Purchase Agreement pursuant to which OTP issued, in a private placement transaction, $120.0 million of senior unsecured notes consisting of (a) $60.0 million of 5.48% Series 2024A Senior Unsecured Notes due April 1, 2034, and (b) $60.0 million of 5.77% Series 2024B Senior Unsecured Notes due April 1, 2054.
Per the terms of the agreement, OTP may prepay all or any part of the notes (in an amount not less than 10% of the aggregate principal amount of the notes then outstanding in the case of a partial prepayment) at 100% of the principal amount so prepaid, together with unpaid accrued interest and a make-whole amount, as defined in the agreement; provided that no default or event of default exists under the agreement. Any prepayment of the Series 2024A Notes then outstanding on or after January 1, 2034, or the Series 2024B Notes then outstanding on or after October 1, 2053, will be made without any make-whole amount. Consistent with other of our borrowings, the agreement contains a number of restrictions on the business of OTP, including restrictions on OTP’s ability to merge, sell substantially all assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in certain transactions with affiliates.
Our guaranteed and unsecured notes require the borrower to maintain various financial covenants, as further described below. These notes provide for prepayment options allowing for a full or partial prepayment at 100% of the principal amount so prepaid, together with unpaid accrued interest and a make-whole amount, as defined. These notes also include restrictions on the borrower, including its ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party and engage in transactions with related parties. The notes include a cross-default provision whereby an event of default of other outstanding indebtedness will trigger an event of default under the note.
Aggregate maturities of long-term debt obligations on December 31, 2024 for each of the next five years are as follows:
| (in thousands) | 2025 | 2026 | 2027 | 2028 | 2029 | ||||||||||||||||||||||||
| Debt Maturities | $ | — | $ | 80,000 | $ | 42,000 | $ | — | $ | 70,000 | |||||||||||||||||||
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 either 0.60 to 1.00 or 0.65 to 1.00, depending on the debt agreement, a minimum interest and dividend coverage ratio of 1.50 to 1.00, and a maximum level of priority indebtedness. As of December 31, 2024, OTC and OTP were in compliance with these financial covenants.
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Guaranties
OTC's obligations under the terms of its Guaranteed Senior Notes are unconditionally and irrevocably guaranteed by its subsidiaries, Varistar Corporation, BTD Manufacturing, Inc., Northern Pipe Products, Inc. and Vinyltech Corporation.
11. Employee Postretirement Benefits
Pension Plan and Other Postretirement Benefits
The Company sponsors a noncontributory funded pension plan (the Pension Plan), an unfunded, nonqualified Executive Survivor and Supplemental Retirement Plan (ESSRP), both accounted for as defined benefit pension plans, and a postretirement healthcare plan accounted for as an other postretirement benefit plan.
The Pension Plan, which previously covered substantially all corporate and OTP employees, was closed to new employees in 2013. The plan provides retirement compensation to all covered employees at age 65, with reduced compensation in cases of retirement prior to age 62. Participants are fully vested after completing five years of vesting service. The plan assets consist of equity funds, fixed income funds, cash and cash equivalents and alternative investments. None of the plan assets are invested in common stock or debt securities of the Company.
The ESSRP, an unfunded plan, provides for defined benefit payments to executive officers and certain key management employees on their retirement for life, or to their beneficiaries on their death. The ESSRP was amended and restated in 2019 to i) freeze the participation in the restoration retirement benefit component of the plan and ii) freeze benefit accruals under the restoration retirement benefit component of the plan for all participants of the plan except any participants deemed to be grandfathered participants.
The postretirement healthcare plan, closed to new participants in 2010, provides a portion of health insurance benefits for retired and covered corporate and OTP employees. To be eligible for retiree health insurance benefits, the employee must be 55 years of age with a minimum of 10 years of service. The plan is an unfunded plan and accordingly holds no plan assets.
Pension Plan Assets. We have established a Retirement Plans Administration Committee to develop and monitor our investment strategy for our Pension Plan assets. Our investment strategy includes the following objectives:
•The assets of the plan will be invested in accordance with all applicable laws in a manner consistent with fiduciary standards including Employee Retirement Income Security Act standards of 1974 (ERISA) (if applicable). Specifically:
◦The safeguards and diversity that a prudent investor would adhere to must be present in the investment program.
◦All transactions undertaken on behalf of the Pension Plan must be in the best interest of plan participants and their beneficiaries.
•The primary objective is to provide a source of retirement income for its participants and beneficiaries.
•The near-term primary financial objective is to improve and protect the funded status of the plan.
•A secondary financial objective is to minimize pension funding and expense volatility where possible.
We have developed an asset allocation target, measured at investment market value, to provide guideline percentages of investment mix. This investment mix is intended to achieve the financial objectives of the plan. The permitted range is a guide and will at times not reflect the actual asset allocation due to market conditions, actions of our investment managers and required cash flows to and from the Pension Plan.
The following table presents our target asset allocation permitted range along with the actual asset allocation as of December 31, 2024 and 2023:
| Permitted | Actual Allocation | ||||||||||||||||||||||
| Asset Class | Range | 2024 | 2023 | ||||||||||||||||||||
| Return Enhancement | 35 | – | 60% | 41 | % | 48 | % | ||||||||||||||||
| Risk Management | 40 | – | 80% | 59 | 51 | ||||||||||||||||||
| Alternatives | 0 | – | 20% | — | 1 | ||||||||||||||||||
| Total | 100 | % | 100 | % | |||||||||||||||||||
Return Enhancement investments are those that seek to provide equity-like, long-term capital appreciation. Examples include equity securities, including dynamic asset allocation funds, and higher yielding fixed income securities, such as high yield bonds and emerging market debt.
Risk Management investments seek to decrease downside risk or act as a hedge against plan liabilities. Examples are cash and fixed income instruments.
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Alternative investments seek to either provide return enhancement through long-term appreciation or risk management through decreased downside risk. The defining characteristic of these asset types is uncorrelated source of returns, less liquidity and private market access. Examples include investments in the SEI Energy Debt Collective Fund.
The following presents the fair value inputs classified within the fair value hierarchy used to measure Pension Plan assets at December 31, 2024 and 2023 and assets measured using the net asset value (NAV) practical expedient:
| (in thousands) | Level 1 | Level 2 | Level 3 | NAV | Total | ||||||||||||||||||||||||
| December 31, 2024 | |||||||||||||||||||||||||||||
| Equity Funds | $ | 116,889 | $ | — | $ | — | $ | — | $ | 116,889 | |||||||||||||||||||
| Fixed Income Funds | 175,310 | — | — | — | 175,310 | ||||||||||||||||||||||||
| Hybrid Funds | 10,106 | — | — | — | 10,106 | ||||||||||||||||||||||||
| U.S. Treasury Securities | 23,909 | — | — | — | 23,909 | ||||||||||||||||||||||||
| SEI Energy Debt Collective Fund | — | — | — | 1,061 | 1,061 | ||||||||||||||||||||||||
| Total | $ | 326,214 | $ | — | $ | — | $ | 1,061 | $ | 327,275 | |||||||||||||||||||
| December 31, 2023 | |||||||||||||||||||||||||||||
| Equity Funds | $ | 127,159 | $ | — | $ | — | $ | — | $ | 127,159 | |||||||||||||||||||
| Fixed Income Funds | 167,604 | — | — | — | 167,604 | ||||||||||||||||||||||||
| Hybrid Funds | 10,980 | — | — | — | 10,980 | ||||||||||||||||||||||||
| U.S. Treasury Securities | 23,218 | — | — | — | 23,218 | ||||||||||||||||||||||||
| SEI Energy Debt Collective Fund | — | — | — | 1,518 | 1,518 | ||||||||||||||||||||||||
| Total | $ | 328,961 | $ | — | $ | — | $ | 1,518 | $ | 330,479 | |||||||||||||||||||
The investments held by the SEI Energy Debt Collective Fund on December 31, 2024 and 2023 consist mainly of below investment grade high yield bonds and loans of U.S. energy companies which trade at a discount to fair value. Redemptions are allowed semi-annually with a 95-day notice period, subject to fund director consent and certain gate, holdback and suspension restrictions. Subscriptions are allowed monthly with a three-year lock up on subscriptions. The fund’s assets are valued in accordance with valuations reported by the fund’s sub-advisor or the fund’s underlying investments or other independent third-party sources, although SEI, in its discretion, may use other valuation methods, subject to compliance with ERISA, as applicable. On an annual basis, as determined by the investment manager in its sole discretion, an independent valuation agent is retained to provide a valuation of the illiquid assets of the fund and of any other asset of the fund.
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Funded Status. The following table provides a reconciliation of the changes in the fair value of plan assets and the actuarially computed benefit obligation for the years ended December 31, 2024 and 2023 and the funded status of the plans as of December 31, 2024 and 2023:
| Pension Benefits (Pension Plan) | Pension Benefits (ESSRP) | Postretirement Benefits | |||||||||||||||||||||||||||||||||
| (in thousands) | 2024 | 2023 | 2024 | 2023 | 2024 | 2023 | |||||||||||||||||||||||||||||
| Change in Fair Value of Plan Assets: | |||||||||||||||||||||||||||||||||||
| Fair Value of Plan Assets at January 1 | $ | 330,479 | $ | 313,797 | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||||||
| Actual Return on Plan Assets | 14,976 | 34,196 | — | — | — | — | |||||||||||||||||||||||||||||
| Company Contributions | — | — | 2,694 | 2,197 | 1,568 | 3,167 | |||||||||||||||||||||||||||||
| Benefit Payments | (18,180) | (17,514) | (2,694) | (2,197) | (3,734) | (8,900) | |||||||||||||||||||||||||||||
| Participant Premium Payments | — | — | — | — | 2,166 | 5,733 | |||||||||||||||||||||||||||||
| Fair Value of Plan Assets at December 31 | $ | 327,275 | $ | 330,479 | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||||||
| Change in Benefit Obligation: | |||||||||||||||||||||||||||||||||||
| Benefit Obligation at January 1 | $ | 318,801 | $ | 308,055 | $ | 35,780 | $ | 35,624 | $ | 30,145 | $ | 49,947 | |||||||||||||||||||||||
| Service Cost | 3,886 | 3,698 | — | 72 | 490 | 565 | |||||||||||||||||||||||||||||
| Interest Cost | 17,189 | 16,436 | 1,897 | 1,889 | 1,600 | 2,416 | |||||||||||||||||||||||||||||
| Benefit Payments | (18,180) | (17,514) | (2,694) | (2,197) | (3,734) | (8,900) | |||||||||||||||||||||||||||||
| Participant Premium Payments | — | — | — | — | 2,166 | 5,733 | |||||||||||||||||||||||||||||
| Plan Amendments | — | — | — | — | — | (17,493) | |||||||||||||||||||||||||||||
| Actuarial (Gain) Loss | (7,686) | 8,126 | 331 | 392 | (664) | (2,123) | |||||||||||||||||||||||||||||
| Benefit Obligation at December 31 | 314,010 | 318,801 | 35,314 | 35,780 | 30,003 | 30,145 | |||||||||||||||||||||||||||||
| Funded Status | $ | 13,265 | $ | 11,678 | $ | (35,314) | $ | (35,780) | $ | (30,003) | $ | (30,145) | |||||||||||||||||||||||
| Amounts Recognized in Consolidated Balance Sheets at December 31: | |||||||||||||||||||||||||||||||||||
| Noncurrent Assets | $ | 13,265 | $ | 11,678 | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||||||
| Current Liabilities | — | — | (2,700) | (2,679) | (2,618) | (2,469) | |||||||||||||||||||||||||||||
Noncurrent Liabilities | — | — | (32,614) | (33,101) | (27,385) | (27,676) | |||||||||||||||||||||||||||||
| Net Asset (Liability) | $ | 13,265 | $ | 11,678 | $ | (35,314) | $ | (35,780) | $ | (30,003) | $ | (30,145) | |||||||||||||||||||||||
The accumulated benefit obligation of our Pension Plan was $288.5 million and $288.8 million as of December 31, 2024 and 2023. The accumulated benefit obligation of our ESSRP was $35.3 million and $35.8 million as of December 31, 2024 and 2023.
The following assumptions were used to determine benefit obligations as of December 31, 2024 and 2023:
The measurement of the plan asset or benefit obligation recognized for our Pension Plan, ESSRP and postretirement healthcare benefit plan included the following significant actuarial adjustments:
•For the Pension Plan, an increase in the discount rate in 2024 and 2023 reduced our obligation by $4.7 million and $2.2 million. Changes in plan participant census data decreased our benefit obligation by $3.0 million in 2024. Actual
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returns on Pension Plan assets in 2024 were $15.0 million, compared to an expected return of $25.5 million, impacting our net obligation by $10.5 million.
•For the ESSRP, an increase in the discount rate in 2024 and 2023 reduced our obligation by $0.2 million and $0.1 million.
•For the postretirement healthcare plan, an increase in the discount rate in 2024 and 2023 reduced our obligation by $0.2 million and $1.3 million. Revised estimates of healthcare cost trends and participant contribution assumptions increased the benefit obligation by $0.4 million in 2024. Changes in plan participant census data decreased our benefit obligation by $0.9 million in 2024.
Net Periodic Benefit Cost. A portion of service cost may be capitalized as a cost of self-constructed property, plant and equipment. When recognized in the consolidated statements of income, service cost is recognized within one of the components of operating expenses. Nonservice cost components of net periodic benefit cost may be deferred and recognized as a regulatory asset under the accounting guidance for regulated operations. When recognized in the consolidated statements of income, nonservice cost components are recognized as nonservice cost components of postretirement benefits.
The following table lists the components of net periodic benefit cost of our defined benefit pension plans and other postretirement benefits for the years ended December 31, 2024, 2023 and 2022:
| Pension Benefits (Pension Plan) | Pension Benefits (ESSRP) | Postretirement Benefits | |||||||||||||||||||||||||||||||||||||||||||||||||||
| (in thousands) | 2024 | 2023 | 2022 | 2024 | 2023 | 2022 | 2024 | 2023 | 2022 | ||||||||||||||||||||||||||||||||||||||||||||
| Service Cost | $ | 3,886 | $ | 3,698 | $ | 6,576 | $ | — | $ | 72 | $ | 195 | $ | 490 | $ | 565 | $ | 1,338 | |||||||||||||||||||||||||||||||||||
| Interest Cost | 17,189 | 16,436 | 12,344 | 1,897 | 1,889 | 1,341 | 1,600 | 2,416 | 2,041 | ||||||||||||||||||||||||||||||||||||||||||||
| Expected Return on Assets | (25,518) | (25,914) | (23,684) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Amortization of Prior Service Cost | — | — | — | — | — | — | (6,302) | (6,649) | (5,733) | ||||||||||||||||||||||||||||||||||||||||||||
| Amortization of Net Actuarial Loss | 158 | — | 7,865 | — | — | 567 | — | — | 3,063 | ||||||||||||||||||||||||||||||||||||||||||||
| Net Periodic Benefit Cost | $ | (4,285) | $ | (5,780) | $ | 3,101 | $ | 1,897 | $ | 1,961 | $ | 2,103 | $ | (4,212) | $ | (3,668) | $ | 709 | |||||||||||||||||||||||||||||||||||
The following table includes the impact of regulation on the recognition of periodic benefit cost arising from pension and other postretirement benefits for the years ended December 31, 2024, 2023 and 2022:
| (in thousands) | 2024 | 2023 | 2022 | ||||||||||||||
| Net Periodic Benefit Cost | $ | (6,600) | $ | (7,487) | $ | 5,913 | |||||||||||
| Net Amount Amortized Due to the Effect of Regulation | 1,367 | 1,225 | 1,121 | ||||||||||||||
| Net Periodic Benefit Cost Recognized | $ | (5,233) | $ | (6,262) | $ | 7,034 | |||||||||||
The following assumptions were used to determine net periodic benefit cost for the years ended December 31, 2024, 2023 and 2022:
We develop our estimated discount rate through the use of a hypothetical bond portfolio method. This method derives the discount rate from the average yield of a collection of high credit quality bonds which produce cash flows similar to our anticipated future benefit payments. We estimate the assumed long-term rate of return on plan assets based primarily on asset category studies using historical market return and volatility data with forward-looking estimates based on existing financial market conditions and forecasts of capital markets. Modest excess return expectations versus some market indices are incorporated into the return projections based on the actively managed structure of the investment programs and their records of achieving such returns historically.
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The following table presents the amounts not yet recognized as components of net periodic benefit cost as of December 31, 2024 and 2023:
| Pension Benefits (Pension Plan) | Pension Benefits (ESSRP) | Postretirement Benefits | |||||||||||||||||||||||||||||||||
| (in thousands) | 2024 | 2023 | 2024 | 2023 | 2024 | 2023 | |||||||||||||||||||||||||||||
| Regulatory Assets (Liabilities): | |||||||||||||||||||||||||||||||||||
| Unrecognized Prior Service Cost | $ | — | $ | — | $ | — | $ | — | $ | (12,703) | $ | (18,845) | |||||||||||||||||||||||
| Unrecognized Actuarial Loss | 87,868 | 85,227 | 292 | 1,061 | 1,121 | 1,759 | |||||||||||||||||||||||||||||
| Net Regulatory Assets (Liabilities) | $ | 87,868 | $ | 85,227 | $ | 292 | $ | 1,061 | $ | (11,582) | $ | (17,086) | |||||||||||||||||||||||
| Accumulated Other Comprehensive Income (Loss): | |||||||||||||||||||||||||||||||||||
| Unrecognized Prior Service Cost | $ | — | $ | — | $ | — | $ | — | $ | 339 | $ | 498 | |||||||||||||||||||||||
| Unrecognized Actuarial Gain (Loss) | 1,937 | 1,994 | (2,502) | (1,403) | 732 | 707 | |||||||||||||||||||||||||||||
| Total Accumulated Other Comprehensive Income (Loss) | $ | 1,937 | $ | 1,994 | $ | (2,502) | $ | (1,403) | $ | 1,071 | $ | 1,205 | |||||||||||||||||||||||
Cash Flows. We did not make any contributions to our Pension Plan in 2024 or 2023. We made a discretionary contribution of $20.0 million in in 2022. As of December 31, 2024, we had no minimum funding requirements for our Pension Plan. Contributions to our ESSRP and postretirement healthcare plan are equal to the benefits paid to plan participants.
The following reflects anticipated benefit payments to be paid in each of the next five years and in the aggregate for the five-year period thereafter under our pension plans and postretirement healthcare plan:
| (in thousands) | 2025 | 2026 | 2027 | 2028 | 2029 | 2030-2034 | |||||||||||||||||||||||||||||
| Projected Pension Plan Benefit Payments | $ | 19,274 | $ | 19,804 | $ | 20,284 | $ | 20,859 | $ | 21,420 | $ | 111,275 | |||||||||||||||||||||||
| Projected ESSRP Benefit Payments | 2,769 | 2,899 | 3,059 | 2,999 | 3,070 | 14,275 | |||||||||||||||||||||||||||||
| Projected Postretirement Benefit Payments | 2,618 | 2,614 | 2,576 | 2,488 | 2,517 | 12,019 | |||||||||||||||||||||||||||||
| Total | $ | 24,661 | $ | 25,317 | $ | 25,919 | $ | 26,346 | $ | 27,007 | $ | 137,569 | |||||||||||||||||||||||
401K Plan
We sponsor a 401K plan for the benefit of all corporate and subsidiary company employees. Contributions made to these plans totaled $9.3 million for 2024, $7.8 million for 2023 and $6.7 million for 2022.
12. Asset Retirement Obligations
We have recognized asset retirement obligations (AROs) related to our coal-fired generation plants, natural gas combustion turbines, solar facility and wind turbines. The cost of AROs include items such as site restoration, closure or removal of ash pits and removal of certain structures, generators, asbestos and storage tanks. We have other legal obligations associated with the retirement of a variety of other long-lived tangible assets used in electric operations where the estimated settlement costs are individually and collectively immaterial. We have no assets legally restricted for the settlement of any AROs. As of December 31, 2024 and 2023, $0.1 million and $0.1 million, respectively, was included in other current liabilities and $42.1 million and $36.4 million, respectively, was included in other noncurrent liabilities in the consolidated balance sheets related to AROs.
A reconciliation of the carrying amounts of AROs for the years ended December 31, 2024 and 2023 is as follows:
| (in thousands) | 2024 | 2023 | |||||||||
| Beginning Balance | $ | 36,477 | $ | 25,182 | |||||||
| New Obligations Recognized | 2,991 | 4,506 | |||||||||
| Adjustments Due to Revisions in Cash Flow Estimates | 1,098 | 8,394 | |||||||||
| Accrued Accretion | 1,676 | 1,191 | |||||||||
| Settlements | (79) | (2,796) | |||||||||
| Ending Balance | $ | 42,163 | $ | 36,477 | |||||||
Coal Combustion Residual Regulations
In May 2024, the Environmental Protection Agency (EPA) published a final rule amending coal combustion residual (CCR) regulations. The final rule introduces new requirements for the management of coal ash at active coal-fired power plants and inactive coal-fired
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power plants with a legacy surface impoundment. The regulations impose new requirements including groundwater monitoring, closure standards, post-closure care obligations and potential remediation activities. At this time, we do not believe there are any significant new requirements which are applicable to our coal-fired power plants, except for Big Stone Plant. During the fourth quarter of 2024, a site evaluation was performed at Big Stone Plant to assess the presence and estimated volumes of coal ash stored at the facility. Based on this and our assessment of the regulations, we believe the plant will be impacted by the new requirements. As of December 31, 2024, we recognized $3.0 million of additional liabilities for new obligations resulting from the EPA's final CCR rule for costs associated with coal ash removal and groundwater monitoring we expect to incur in the future. The final rule requires facility evaluations to be performed in the future. Revisions to our estimated compliance costs or further obligations could be identified through the process of performing the additional evaluations. Should such revisions be necessary or if additional cost obligations are identified, we will update our cash flow estimates and resulting retirement obligation at that time.
13. Income Taxes
Income before income taxes for the years ended December 31, 2024, 2023 and 2022 consists entirely of domestic earnings.
The provision for income taxes charged to income for the years ended December 31, 2024, 2023 and 2022 consisted of the following:
| (in thousands) | 2024 | 2023 | 2022 | ||||||||||||||
| Current | |||||||||||||||||
| Federal Income Taxes | $ | 36,238 | $ | 41,253 | $ | 31,949 | |||||||||||
| State Income Taxes | 6,533 | 15,126 | 9,568 | ||||||||||||||
| Deferred | |||||||||||||||||
| Federal Income Taxes | 13,078 | 9,832 | 22,480 | ||||||||||||||
| State Income Taxes | 9,979 | 3,676 | 9,943 | ||||||||||||||
| Tax Credits | |||||||||||||||||
| North Dakota Wind Tax Credit Amortization, Net of Federal Tax | (586) | (586) | (586) | ||||||||||||||
| Investment Tax Credit Amortization | (12) | (3) | (3) | ||||||||||||||
| Total | $ | 65,230 | $ | 69,298 | $ | 73,351 | |||||||||||
The reconciliation of the statutory federal income tax rate to our effective tax rate for each of the years ended December 31, 2024, 2023 and 2022 is as follows:
| 2024 | 2023 | 2022 | ||||||||||||||||||||||||
| Income Taxes at Federal Statutory Rate | $ | 77,047 | 21.0 | % | $ | 76,332 | 21.0 | % | $ | 75,082 | 21.0 | % | ||||||||||||||
| Increases (Decreases) in Tax from: | ||||||||||||||||||||||||||
| State Taxes on Income, Net of Federal Tax | 14,360 | 3.9 | 14,429 | 4.0 | 15,049 | 4.2 | ||||||||||||||||||||
| Production Tax Credits (PTCs) | (20,106) | (5.5) | (17,394) | (4.8) | (14,985) | (4.2) | ||||||||||||||||||||
| Amortization of Excess Deferred Income Taxes | (2,788) | (0.8) | (2,205) | (0.6) | (1,625) | (0.5) | ||||||||||||||||||||
| North Dakota Wind Tax Credit Amortization, Net of Federal Tax | (586) | (0.2) | (586) | (0.2) | (586) | (0.2) | ||||||||||||||||||||
| Other, Net | (2,697) | (0.6) | (1,278) | (0.3) | 416 | 0.2 | ||||||||||||||||||||
| Income Taxes at Effective Tax Rate | $ | 65,230 | 17.8 | % | $ | 69,298 | 19.1 | % | $ | 73,351 | 20.5 | % | ||||||||||||||
PTCs, North Dakota wind tax credits and excess deferred income taxes arising from the federal tax rate reduction in the 2017 Tax Cuts and Jobs Act are returned to customers as a reduction of the rates they are charged and result in a reduction of operating revenues.
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Deferred tax assets and liabilities were composed of the following on December 31, 2024 and 2023:
| (in thousands) | 2024 | 2023 | |||||||||
| Deferred Tax Assets | |||||||||||
| Employee Benefits | $ | 37,456 | $ | 39,959 | |||||||
| Regulatory Liabilities | 52,664 | 56,479 | |||||||||
| Tax Credit Carryforwards | 18,268 | 21,836 | |||||||||
| Cost of Removal | 35,374 | 32,993 | |||||||||
| Asset Retirement Obligations | 10,948 | 9,494 | |||||||||
| Net Operating Loss Carryforward | 2,289 | 2,336 | |||||||||
| Other | 19,449 | 11,310 | |||||||||
| Total Deferred Tax Assets | $ | 176,448 | $ | 174,407 | |||||||
| Deferred Tax Liabilities | |||||||||||
| Differences Related to Property | $ | (375,120) | $ | (347,885) | |||||||
| Retirement Benefits Regulatory Asset | (22,892) | (22,458) | |||||||||
| Pension Expense | (26,034) | (24,875) | |||||||||
| Other | (20,147) | (16,462) | |||||||||
| Total Deferred Tax Liabilities | (444,193) | (411,680) | |||||||||
| Deferred Income Taxes | $ | (267,745) | $ | (237,273) | |||||||
As of December 31, 2024, we had net operating loss carryforwards for state tax purposes totaling $2.3 million that expire between 2029 and 2037, and state tax credits totaling $18.3 million which expire between 2040 and 2043.
The following table summarizes the activity for unrecognized tax benefits for the years ended December 31, 2024, 2023 and 2022:
| (in thousands) | 2024 | 2023 | 2022 | ||||||||||||||
| Balance on January 1 | $ | 1,489 | $ | 923 | $ | 827 | |||||||||||
Increases (Decreases) for tax positions taken during a prior period | (189) | 596 | 44 | ||||||||||||||
| Increases for tax positions taken during the current period | 188 | 163 | 260 | ||||||||||||||
| Decreases due to settlements with taxing authorities | — | — | — | ||||||||||||||
| Decreases as a result of a lapse of applicable statutes of limitations | (363) | (193) | (208) | ||||||||||||||
| Balance on December 31 | $ | 1,125 | $ | 1,489 | $ | 923 | |||||||||||
The balance of unrecognized tax benefits as of December 31, 2024 would reduce our effective tax rate if recognized. The total amount of unrecognized tax benefits as of December 31, 2024 is not expected to change significantly within the next 12 months.
The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of December 31, 2024, with limited exceptions, we are no longer subject to examinations by taxing authorities for tax years prior to 2021 for federal and North Dakota income taxes and prior to 2020 for Minnesota state income taxes.
14. Commitments and Contingencies
Commitments
Electric Utility Capacity and Energy Requirements. OTP has commitments for the purchase of capacity and energy requirements under contractual agreements, including wind power purchase agreements extending into 2048. Generally, the terms of OTP's wind power purchase agreements require OTP to purchase all of the electricity generated by a particular wind farm, but do not include fixed or minimum payments. The required payments are variable and the amounts due are determined based upon the amount of capacity available or electricity generated. Capacity and energy requirement costs under these agreements totaled $6.0 million, $5.6 million and $13.1 million for the years ended December 31, 2024, 2023 and 2022.
Coal Purchase Commitments. OTP has contracts providing for the purchase and delivery of its coal requirements. OTP’s current coal purchase agreement with CCMC for Coyote Station expires on December 31, 2040. All of Coyote Station’s coal requirements for the period covered must be purchased under this agreement. The agreement is structured so that the price of the coal covers all of CCMC's operating, financing and future mine reclamation costs. In the table below, we have estimated the future payments to be made under the terms of the agreement until its maturity. OTP has an agreement for the purchase of Big Stone Plant’s coal requirements through December 31, 2026. There is no fixed minimum purchase requirement, and no amounts for this agreement have been included in the table below; however, under this agreement all of Big Stone Plant’s coal requirements for the period
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covered must be purchased under this agreement. Coal purchase costs under these two agreements totaled $44.7 million, $43.7 million and $45.1 million for the years ended December 31, 2024, 2023 and 2022.
Land Easement Payments. OTP has commitments to make payments for land easements not classified as leases. The contractual terms of these easements are generally 99 years or do not have a stated maturity date; however, per the terms of the agreements, our requirement to make payment ends once we cease use of the land. As such, in the table below, we have included payments under these easements through the estimated useful lives of the facilities associated with the easement. The commitments under these arrangements extend into 2055 and total approximately $62.0 million. Land easement costs under these agreements totaled $1.8 million, $1.8 million and $1.4 million for the years ended December 31, 2024, 2023 and 2022.
Other Commitments. As of December 31, 2024, we had commitments under contracts for plant maintenance, software subscriptions and other services extending into 2046 which totaled approximately $10.6 million.
Our future commitments as of December 31, 2024 were as follows:
| (in thousands) | Coal Purchase Commitments | Land Easement Payments | Other Commitments | ||||||||||||||||||||
| 2025 | $ | 24,192 | $ | 1,897 | $ | 1,817 | |||||||||||||||||
| 2026 | 24,416 | 1,902 | 1,518 | ||||||||||||||||||||
| 2027 | 25,127 | 1,941 | 661 | ||||||||||||||||||||
| 2028 | 25,859 | 1,981 | 544 | ||||||||||||||||||||
| 2029 | 27,102 | 2,021 | 272 | ||||||||||||||||||||
| Beyond 2029 | 314,713 | 52,261 | 5,758 | ||||||||||||||||||||
| Total | $ | 441,409 | $ | 62,003 | $ | 10,570 | |||||||||||||||||
Solar Development. On October 30, 2024, OTP entered into an agreement to acquire the assets of a solar facility currently under development. The assets to be acquired include real property rights and interests, interconnection agreements, state and local permits, and other development assets. Per the agreement, the purchase price is equal to $23.6 million, plus the reimbursement of certain interconnection costs and costs to purchase and store the main power transformer. Closing of the transaction is expected to occur in late 2025 or early 2026, and remains subject to certain conditions to close, including regulatory and other approvals. OTP would be subject to a termination fee of up to $5.0 million if the seller has satisfied all required conditions to close but the transaction is not consummated.
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 issued an order on November 19, 2020, which adopted a revised ROE methodology and set the base ROE at 10.02% (10.52% with an adder) effective for the fifteen-month period from November 2013 to February 2015 and on a prospective basis beginning in September 2016. The order also dismissed any complaints covering the period from February 2015 to May 2016. On August 9, 2022, the U.S. Court of Appeals for the District of Columbia Circuit vacated the FERC order citing a lack of reasoned explanation by FERC in its adoption of its revised ROE methodology as outlined in its November 2020 order and remanded the matter to FERC to reopen the proceedings.
On October 17, 2024, FERC issued an Order on Remand modifying its ROE methodology and establishing a base ROE of 9.98% (10.48% with an adder) effective for the fifteen-month period from November 2013 to February 2015 and on a prospective basis beginning in September 2016, and required MISO transmission owners to provide refunds to customers for collections in excess of the base ROE of 9.98% for the applicable period, plus interest. In addition, FERC concluded the evidentiary record continues to support the ROE established for the period from February 2015 to May 2016.
Prior to FERC's Order on Remand, we had deferred recognition of certain revenues and recognized a refund liability which reflected the amount previously collected under the MISO tariff rate that we anticipated would be refunded to customers. Our previous estimated refund amount was larger than the actual amount ordered by FERC in the Order on Remand and was therefore reduced, which resulted in a pre-tax benefit of $2.5 million recognized in our consolidated statements of income for the year ended December 31, 2024. The balance of the recorded refund liability as of December 31, 2024 was $0.5 million.
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Self-Funding of Transmission Upgrades for Generator Interconnections. FERC has granted transmission owners within MISO and other regional transmission organizations (RTOs) the unilateral authority to determine the funding mechanism for interconnection transmission upgrades that are necessary to accommodate new generation facilities connecting to the electrical grid. Under existing FERC orders, transmission owners can unilaterally determine whether the generator pays the transmission owner in advance for the transmission upgrade or, alternatively, the transmission owner can elect to fund the upgrade and recover over time from the generator the cost of and a return on the upgrade investment (a self-funding). FERC’s orders granting transmission owners this unilateral funding authority have been judicially contested on the basis that transmission owners may be motivated to discriminate among generators in making funding determinations. In the most recent judicial proceedings, the petitioners argued to the U.S. Court of Appeals for the District of Columbia that FERC did not comply with a previous judicial order to fully develop a record regarding the risk of discrimination and the financial risk absorbed by transmission owners for generator-funded upgrades. In December 2022, the Court of Appeals ruled in favor of the petitioners remanding the matter to FERC, instructing the agency to adequately explain the basis of its orders. The Court of Appeals decision did not vacate transmission owners’ unilateral funding authority.
In June 2024, FERC issued an Order to Show Cause proceeding against four RTOs, including MISO. Within its order, FERC indicates that the transmission tariffs of the RTOs appear to be unjust, unreasonable, and unduly discriminatory or preferential because they allow transmission owners to unilaterally elect transmission owner self-funding, which may increase costs, impose barriers to transmission interconnection and result in undue discrimination among interconnection customers.
The order required each RTO to submit filings to either 1) show cause as to why the transmission tariff remains just and reasonable and not duly discriminatory or preferential, or 2) to explain what changes to the tariff it believes would remedy the identified concerns. FERC has received a number of responses to its Order to Show Cause. In September 2024, in separate filings, MISO and transmission owners within MISO, including OTP, filed responses outlining the reasons why the self-funding option remains just and reasonable and not unduly discriminatory or preferential. Other responses have been provided by other RTOs, individual transmission owners, developers of renewable generation facilities and other interested parties.
OTP, as a transmission owner in MISO, has exercised its authority and elected to self-fund previous transmission upgrades necessary to accommodate new system generation. Under such an election, OTP is recovering the cost of the transmission upgrade and a return on that investment from the generator over a contractual period of time. Should the resolution of this matter eliminate transmission owners’ unilateral funding authority on either a prospective or retrospective basis, our financial results would be impacted. We cannot at this time reasonably predict the outcome of this matter given the uncertainty as to how FERC may ultimately decide on the matter after RTOs' filings in response to the Order to Show Cause.
Class Action Lawsuits. Several class action complaints against certain PVC pipe manufacturers, including OTC, have been filed in the U.S. District Court for the Northern District of Illinois alleging violations of antitrust laws. The first of the complaints was filed on August 23, 2024. The various complaints have been consolidated under the caption In re: PVC Pipe Antitrust Litigation (Case No. 1:24-cv-07639). Specifically, the complaints allege, among other things, that beginning in at least January 2021, the defendants conspired and combined to fix, raise, maintain and stabilize the price of PVC municipal water and electrical conduit pipe in violation of U.S. antitrust laws. The plaintiffs are seeking treble damages, injunctive relief, pre- and post-judgment interest, costs and attorneys’ fees.
In addition, on August 27, 2024, the Company received a grand jury subpoena issued by the U.S. District Court for the Northern District of California, from the U.S. Department of Justice (DOJ) Antitrust Division. The subpoena calls for production of documents regarding the manufacturing, selling and pricing of PVC pipe. The Company is responding to the subpoena and intends to comply with its obligations under the subpoena.
At this time, we are unable to determine the likelihood of an outcome or estimate a range of reasonably possible losses, if any, arising from the class action complaints or the DOJ investigation. However, if an antitrust violation by the Company is found, it could have a material impact on the Company’s financial condition, operating results and liquidity. The Company believes that there are factual and legal defenses to the allegations in the complaints and intends to defend itself accordingly.
Other Contingencies. We are party to litigation and regulatory matters arising in the normal course of business. We regularly analyze relevant information and, as necessary, estimate and record accrued liabilities for legal, regulatory enforcement and other 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, 2024, other than those discussed above, will not be material.
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15. Stockholders' Equity
Capital Structure
In addition to authorized and outstanding common stock, the Company has 1,500,000 authorized no par value cumulative preferred shares and 1,000,000 authorized no par value cumulative preference shares. No cumulative preferred or cumulative preference shares were outstanding at December 31, 2024 or 2023.
Registration Statements
On May 3, 2024, we filed a shelf registration statement with the SEC under which we may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement. The registration statement expires in May 2027. No shares were issued pursuant to the shelf registration statement in 2024.
On May 3, 2024, we filed a second registration statement with the SEC for the issuance of up to 1,500,000 common shares under an Automatic Dividend Reinvestment and Share Purchase Plan, which provides shareholders, retail customers of OTP and other interested investors methods of purchasing our common shares by reinvesting their dividends or making optional cash investments. Shares purchased under the plan may be new issue common shares or common shares purchased on the open market. In 2024, we issued 70,469 common shares under this program and no proceeds were received, as all shares issued were purchased on the open market. As of December 31, 2024, 1,429,531 shares remained available for purchase or issuance under the plan. The registration statement expires in May 2027.
Dividend Restrictions
OTC is a holding company with no significant operations of its own. The primary source of funds for payments of dividends to our shareholders is from intercompany distributions made by OTC's subsidiaries to OTC.
As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by OTC's subsidiaries, as further described below:
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, 2024, we were in compliance with these financial covenants.
Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. What constitutes “funds properly included in a capital account” is undefined in the Federal Power Act and the related regulations; however, the FERC has consistently interpreted the provision to allow dividends to be paid as long as i) the source of the dividends is clearly disclosed, ii) the dividend is not excessive and iii) there is no self-dealing on the part of corporate officials.
The MPUC indirectly limits the amount of dividends OTP can pay to OTC by requiring an equity-to-total-capitalization ratio between 47.2% and 57.7%, with total capitalization not to exceed $2.2 billion based on OTP’s capital structure requirements as of December 31, 2024. As of December 31, 2024, OTP’s equity-to-total-capitalization ratio including short-term debt was 53.1% and its net assets restricted from distribution totaled approximately $834.5 million.
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16. Accumulated Other Comprehensive Income (Loss)
The Company's other comprehensive income (loss) consists of unamortized actuarial losses and prior service costs related to pension and other postretirement benefits and unrealized gains and losses on marketable securities classified as available-for-sale. The income tax expense or benefit associated with amounts reclassified from accumulated other comprehensive income (loss) and reflected in the consolidated statements of income are recognized in the same period as the amounts are reclassified.
The following table shows the changes in accumulated other comprehensive Income (loss) for the years ended December 31, 2024, 2023 and 2022:
17. Share-Based Payments
Employee Stock Purchase Plan
The 1999 Employee Stock Purchase Plan authorizes the issuance of 1,400,000 common shares, allowing eligible employees to purchase our common shares through payroll withholding at a discount of up to 15% off the market price at the end of each six-month purchase period. Employee withholding amounts may not be less than $10 or more than $2,000 per month, subject to certain limitations, as described in the plan. A plan participant may cease making payroll deductions at any time. A participant may not purchase more than 2,000 shares in a given six-month purchase period under the plan and may not purchase more than $25,000 (fair market value) of common shares under the plan and all other purchase plans (if any) in a calendar year. A participant may withdraw from the plan at any time and elect to receive the balance of their contributions to the plan that have not yet been used to purchase shares. Shares purchased under the plan are automatically enrolled in the Company's dividend reinvestment plan. Shares purchased under the plan may not be assigned, transferred, pledged, or otherwise disposed, except for certain situations allowed by the plan, such as upon death, for a period of 18 months after purchase. At our discretion, shares purchased under the plan can be either new issue shares or shares purchased in the open market. The plan shall automatically terminate when all of the shares authorized under the plan have been issued.
We recognize the 15% discount to the fair market value of the purchased shares as stock-based compensation expense, which amounted to $0.4 million, $0.3 million and $0.3 million for the years ended December 31, 2024, 2023 and 2022. For the years ended December 31, 2024, 2023 and 2022, the amount of shares issued under the plan amounted to 31,252, 26,348 and 26,420 shares. As of December 31, 2024, there were 206,115 shares available for purchase under the plan.
Share-Based Compensation Plan
The 2023 Stock Incentive Plan, which was approved by our shareholders in April 2023, authorizes the issuance of 979,891 common shares, including 500,000 newly requested common shares, for the granting of stock options, stock appreciation rights, restricted
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stock, restricted stock units, dividend equivalents, performance awards and other stock-based awards. In addition, common shares subject to any outstanding awards under our prior stock incentive plans that are forfeited, canceled or reacquired by the Company will become available for re-issuance under the 2023 Stock Incentive Plan. As of December 31, 2024, 828,761 shares were available for issuance under the plan. The plan terminates on April 17, 2033.
We grant restricted stock awards to our employees and members of our Board of Directors and stock performance awards to our executive officers and certain other key employees as part of our long-term compensation and retention program. Stock-based compensation cost, recognized within operating expenses in the consolidated statements of income, amounted to $9.1 million, $7.4 million and $6.6 million for the years ended December 31, 2024, 2023 and 2022. The related income tax benefit recognized for these periods amounted to $2.7 million, $1.6 million and $1.7 million.
Restricted Stock Awards. Restricted stock awards are granted to executive officers and other key employees and members of the Company's Board of Directors. The awards vest, depending on award recipient, either ratably over a period of to four years or cliff vest after four years. Vesting is accelerated in certain circumstances, including upon retirement. Awards granted to members of the Board of Directors are issued and outstanding upon grant and carry the same voting and dividend rights of unrestricted outstanding common stock. Awards granted to executive officers are eligible to receive dividend equivalent payments during the vesting period, subject to forfeiture under the terms of the agreement, but such awards are not issued or outstanding upon grant and do not provide for voting rights.
The grant-date fair value of each restricted stock award is determined based on the market price of the Company's common stock on the date of grant adjusted to exclude the value of dividends for those awards that do not receive dividend or dividend equivalent payments during the vesting period.
The following is a summary of restricted stock award activity for the year ended December 31, 2024:
| Shares | Weighted-Average Grant-Date Fair Value | ||||||||||
| Nonvested, Beginning of Year | 148,913 | $ | 56.48 | ||||||||
| Granted | 52,425 | 85.25 | |||||||||
| Vested | (57,771) | 52.78 | |||||||||
| Forfeited | (150) | 66.39 | |||||||||
| Nonvested, End of Year | 143,417 | $ | 68.47 | ||||||||
The weighted-average grant-date fair value of granted awards was $85.25, $68.03 and $59.95 during the years ended December 31, 2024, 2023 and 2022. The fair value of vested awards was $5.1 million, $3.1 million and $3.0 million during the years ended December 31, 2024, 2023 and 2022. As of December 31, 2024, there was $3.7 million of unrecognized compensation cost for unvested restricted stock awards to be recognized over a weighted-average period of 1.5 years.
Stock Performance Awards. Stock performance awards are granted to executive officers and certain other key employees. The awards vest at the end of a three-year performance period. The number of common shares awarded, if any, at the end of the performance period ranges from zero to 150% of the target amount based on two performance measures i) total shareholder return relative to a peer group (TSR component) and ii) return on equity (ROE component). The awards have no voting or dividend rights during the vesting period. Vesting of the awards is accelerated in certain circumstances, including upon retirement. The number of common shares awarded on an accelerated vesting is based on actual performance at the end of the performance period.
The grant-date fair value of the ROE component of the stock performance awards granted during the years ended December 31, 2024, 2023 and 2022 was determined using the grant date stock price and a discounted cash flow analysis to adjust for expected unearned dividends during the vesting period. The grant-date fair value of the TSR component of the stock performance awards granted during the years ended December 31, 2024, 2023 and 2022 was determined using a Monte Carlo fair value simulation model incorporating the following assumptions:
| 2024 | 2023 | 2022 | |||||||||||||||
| Risk-free interest rate | 4.16 | % | 4.15 | % | 1.52 | % | |||||||||||
| Expected term (in years) | 3.00 | 3.00 | 3.00 | ||||||||||||||
| Expected volatility | 35.10 | % | 34.00 | % | 32.00 | % | |||||||||||
| Dividend yield | 2.40 | % | 2.50 | % | 2.90 | % | |||||||||||
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The risk-free interest rate was derived from yields on U.S. government bonds of a similar term. The expected term of the award is equal to the three-year performance period. Expected volatility was estimated based on actual historical volatility of our common stock over a five-year period. Dividend yield was estimated based on historic and future yield estimates.
The following is a summary of stock performance award activity for the year ended December 31, 2024 (share amounts reflect awards at target):
| Shares | Weighted-Average Grant-Date Fair Value | ||||||||||
| Nonvested, Beginning of Year | 194,200 | $ | 50.33 | ||||||||
| Granted | 43,400 | 94.45 | |||||||||
| Vested | (92,800) | 42.06 | |||||||||
| Forfeited | — | — | |||||||||
| Nonvested, End of Year | 144,800 | $ | 68.85 | ||||||||
The weighted-average grant-date fair value of granted awards was $94.45, $61.97 and $54.91 during the years ended December 31, 2024, 2023 and 2022. The fair value of vested awards was $12.3 million, $5.3 million and $5.1 million during the years ended December 31, 2024, 2023 and 2022. As of December 31, 2024, there was $0.5 million of unrecognized compensation cost of unvested stock performance awards to be recognized over a weighted-average period of 0.65 years.
18. Earnings Per Share
The numerator used in the calculation of both basic and diluted earnings per share is net income. The denominator used in the calculation of basic earnings per share is the weighted-average number of shares outstanding during the period. The denominator used in the calculation of diluted earnings per share is derived by adjusting basic shares outstanding for the dilutive effect of potential shares outstanding, which consist of shares associated with time- and performance-based stock awards and our employee stock purchase plan.
The following includes the computation of the denominator for basic and diluted weighted-average shares outstanding for the years ended December 31, 2024, 2023 and 2022:
| (in thousands) | 2024 | 2023 | 2022 | ||||||||||||||
| Weighted Average Common Shares Outstanding – Basic | 41,778 | 41,668 | 41,586 | ||||||||||||||
| Effect of Dilutive Securities: | |||||||||||||||||
| Stock Performance Awards | 196 | 269 | 248 | ||||||||||||||
| Restricted Stock Awards | 96 | 100 | 95 | ||||||||||||||
| Employee Stock Purchase Plan Shares and Other | 2 | 2 | 2 | ||||||||||||||
| Dilutive Effect of Potential Common Shares | 294 | 371 | 345 | ||||||||||||||
| Weighted Average Common Shares Outstanding – Diluted | 42,072 | 42,039 | 41,931 | ||||||||||||||
The number 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, 2024, 2023 and 2022.
19. Derivative Instruments
OTP enters into derivative instruments to manage its exposure to future commodity price variability, specifically future wholesale energy and natural gas prices, and reduce volatility in prices for our retail electric customers. These derivative instruments are not designated as qualifying hedging transactions but provide for an economic hedge against future price variability. The instruments are recorded at fair value on the consolidated balance sheets on a gross basis with assets and liabilities presented separately. In
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accordance with rate-making and cost recovery processes, we recognize a regulatory asset or liability to defer losses or gains from derivative activity until settlement of the associated derivative instrument.
As of December 31, 2024 and 2023, OTP had multiple outstanding pay-fixed, receive-variable swap agreements. The contracts outstanding as of December 31, 2024 had various settlement dates throughout 2025. The following presents the notional amounts and fair value of our derivative instruments as of December 31, 2024 and 2023:
| (in thousands) | 2024 | 2023 | |||||||||
| Megawatt hours of electricity | 167 | 187 | |||||||||
| Derivative Liabilities: | |||||||||||
| Other Current Liabilities | $ | 1,989 | $ | 4,210 | |||||||
| Other Noncurrent Liabilities | — | — | |||||||||
| Total Derivative Liabilities | $ | 1,989 | $ | 4,210 | |||||||
During the years ended December 31, 2024 and 2023, contracts matured and were settled in an aggregate amount of a $3.5 million loss and a $16.5 million loss, respectively. Gains and losses recognized on the settlement of derivative instruments are returned to, or recovered from, our electric customers through fuel recovery mechanisms in each state. When recognized in the consolidated statements of income, these gains or losses are included in electric purchased power. Gains or losses related to the settlement of derivative instruments are included in cash flows from operations in the consolidated statements of cash flows.
20. Fair Value Measurements
The following tables present our assets and liabilities measured at fair value on a recurring basis as of December 31, 2024 and 2023 classified by the input method used to measure fair value:
| Level 1 | Level 2 | Level 3 | |||||||||||||||
| December 31, 2024 | |||||||||||||||||
| Assets | |||||||||||||||||
| Investments: | |||||||||||||||||
| Money Market Funds | $ | 596 | $ | — | $ | — | |||||||||||
| Mutual Funds | 10,653 | — | — | ||||||||||||||
| Corporate Debt Securities | — | 1,628 | — | ||||||||||||||
| Government Debt Securities | — | 61,131 | — | ||||||||||||||
| Total Assets | 11,249 | 62,759 | — | ||||||||||||||
| Liabilities | |||||||||||||||||
| Derivative Instruments | — | 1,989 | — | ||||||||||||||
| Total Liabilities | $ | — | $ | 1,989 | $ | — | |||||||||||
| (in thousands) | Level 1 | Level 2 | Level 3 | ||||||||||||||
| December 31, 2023 | |||||||||||||||||
| Assets | |||||||||||||||||
| Investments: | |||||||||||||||||
| Money Market Funds | $ | 3,125 | $ | — | $ | — | |||||||||||
| Mutual Funds | 7,771 | — | — | ||||||||||||||
| Corporate Debt Securities | — | 1,579 | — | ||||||||||||||
| Government Debt Securities | — | 7,724 | — | ||||||||||||||
| Total Assets | $ | 10,896 | $ | 9,303 | $ | — | |||||||||||
| Liabilities | |||||||||||||||||
| Derivative Instruments | $ | — | $ | 4,210 | $ | — | |||||||||||
| Total Liabilities | $ | — | $ | 4,210 | $ | — | |||||||||||
Level 1 fair value measurements are based on quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access at the measurement date.
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The level 2 fair value measurements for government and corporate debt securities are determined based on valuations provided by third parties which utilize industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing services may be based on broker quotes.
The level 2 fair value measurements for derivative instruments are determined by using inputs such as forward electric commodity prices, adjusted for location differences. These inputs are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
In addition to assets recorded at fair value on a recurring basis, we also hold financial instruments that are not recorded at fair value in the consolidated balance sheets but for which disclosure of the fair value of these financial instruments is provided. The following reflects the carrying value and estimated fair value of these assets and liabilities as of December 31, 2024 and 2023:
| December 31, 2024 | December 31, 2023 | ||||||||||||||||||||||
| (in thousands) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Cash and Cash Equivalents | $ | 294,651 | $ | 294,651 | $ | 230,373 | $ | 230,373 | |||||||||||||||
| Total | 294,651 | 294,651 | 230,373 | 230,373 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||
| Short-Term Debt | 69,615 | 69,615 | 81,422 | 81,422 | |||||||||||||||||||
| Long-Term Debt | 943,734 | 806,826 | 824,059 | 710,839 | |||||||||||||||||||
| Total | $ | 1,013,349 | $ | 876,441 | $ | 905,481 | $ | 792,261 | |||||||||||||||
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 fair value:
Cash Equivalents: The carrying amount approximates fair value because of the short-term maturity of these instruments. Fair value is determined based on quoted prices in active markets, a Level 1 fair value input.
Short-Term Debt: The carrying amount approximates fair value because the debt obligations are short-term in nature and balances outstanding are subject to variable rates of interest which reset frequently, a Level 2 fair value input.
Long-Term Debt: The fair value of long-term debt is estimated based on current market indications for borrowings of similar maturities with similar terms, a Level 2 fair value input.
| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE | ||||
None.
| 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, 2024, 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, 2024.
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, 2024 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-
85
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, 2024. 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, 2024, the Company’s internal control over financial reporting was effective based on those criteria. The Company’s independent registered public accounting firm, Deloitte & Touche LLP, has audited the Company’s consolidated financial statements included in this report on Form 10-K and issued an attestation report on the Company’s internal control over financial reporting.
Attestation Report of Independent Registered Public Accounting Firm. The attestation report of Deloitte & Touche LLP, the Company’s independent registered public accounting firm, regarding the Company’s internal control over financial reporting is provided in Item 8 of this report on Form 10-K.
| ITEM 9B. | OTHER INFORMATION | ||||
None.
| ITEM 9C. | DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS | ||||
Not applicable.
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PART III
| ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE | ||||
The information required by this Item is incorporated by reference to the information under “Election of Directors,” "Corporate Governance - Director Nomination Process," "Committees of the Board of Directors - Audit Committee," and "Executive Compensation Policies - Insider Trading Policy" in the Company's definitive Proxy Statement for the 2025 Annual Meeting. The information regarding executive officers and family relationships is set forth in Item 3A of this report on Form 10-K.
The Company has adopted a code of business ethics that applies to all of its directors, officers (including its principal executive officer, principal financial officer, and its principal accounting officer or controller or person performing similar functions) and employees. The Company’s code of business ethics is available on its website at www.ottertail.com. The Company intends to satisfy the disclosure requirements under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of its code of business ethics by posting such information on its website at the address specified above. Information on the Company’s website is not deemed to be incorporated by reference into this report on Form 10-K.
| 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,” "Director Independence Determinations" and “Committees of the Board of Directors” in the Company’s definitive Proxy Statement for the 2025 Annual Meeting.
| ITEM 11. | EXECUTIVE COMPENSATION | ||||
The information required by this Item is incorporated by reference to the information under “Compensation Discussion and Analysis,” “Report of Compensation and Human Capital Management Committee,” “Executive Compensation,” “Pay Ratio Disclosure” and “Director Compensation” in the Company's definitive Proxy Statement for the 2025 Annual Meeting.
| 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 2025 Annual Meeting.
The following table sets forth information as of December 31, 2024 about the Company’s common stock that may be issued under all its equity compensation plans:
| Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | |||||||||||||||||||||
| Plan Category | (a) | (b) | (c) | ||||||||||||||||||||
| Equity compensation plans approved by security holders: | |||||||||||||||||||||||
| 2023 Stock Incentive Plan | 333,147 | '(1) | N/A | 828,761 | '(2) | ||||||||||||||||||
| 1999 Employee Stock Purchase Plan | — | N/A | '(3) | ||||||||||||||||||||
| Equity compensation plans not approved by security holders | — | — | 206,115 | ||||||||||||||||||||
| Total | 333,147 | — | 1,034,876 | ||||||||||||||||||||
(1)Includes 65,100, 78,600 and 73,500 performance-based share awards, assuming a maximum payout, granted in 2024, 2023 and 2022, respectively, and 115,947 restricted stock units outstanding as of December 31, 2024.
(2)The 2023 Stock Incentive Plan provides for the issuance of any shares available under the plan in the form of restricted stock, restricted stock units, performance awards and other types of stock-based awards, in addition to the granting of options, warrants or stock appreciation rights.
(3)Shares to be issued based on employee’s election to participate in the plan.
87
| 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 2025 Annual Meeting.
88
PART IV
| ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES | ||||
1. Financial Statements
| Page | |||||
Consolidated Balance Sheets | |||||
Consolidated Statements of Income | |||||
2. Financial Statement Schedules
Schedule I - Condensed Financial Information of Registrant
Schedule II - Valuation and Qualifying Accounts and Reserves
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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
OTTER TAIL CORPORATION (PARENT COMPANY)
CONDENSED BALANCE SHEETS
| December 31, | |||||||||||
| (in thousands) | 2024 | 2023 | |||||||||
| Assets | |||||||||||
| Current Assets | |||||||||||
| Cash and Cash Equivalents | $ | 291,575 | $ | 228,137 | |||||||
| Accounts Receivable from Subsidiaries | 5,642 | 2,555 | |||||||||
| Interest Receivable from Subsidiaries | 117 | 117 | |||||||||
| Notes Receivable from Subsidiaries | 4,706 | — | |||||||||
| Other | 3,538 | 977 | |||||||||
| Total Current Assets | 305,578 | 231,786 | |||||||||
| Investments in Subsidiaries | 2,006,239 | 1,725,584 | |||||||||
| Notes Receivable from Subsidiaries | 78,900 | 78,900 | |||||||||
| Deferred Income Taxes | 69,781 | 65,244 | |||||||||
| Other Assets | 109,057 | 50,795 | |||||||||
| Total Assets | $ | 2,569,555 | $ | 2,152,309 | |||||||
| Liabilities and Stockholders' Equity | |||||||||||
| Current Liabilities | |||||||||||
| Accounts Payable to Subsidiaries | $ | 7 | $ | 7 | |||||||
| Notes Payable to Subsidiaries | 752,625 | 568,672 | |||||||||
| Other | 19,100 | 15,320 | |||||||||
| Total Current Liabilities | 771,732 | 583,999 | |||||||||
| Other Noncurrent Liabilities | 49,424 | 45,455 | |||||||||
| Commitments and Contingencies | |||||||||||
| Capitalization | |||||||||||
| Long-Term Debt | 79,900 | 79,849 | |||||||||
| Common Stockholders' Equity | 1,668,499 | 1,443,006 | |||||||||
| Total Capitalization | 1,748,399 | 1,522,855 | |||||||||
| Total Liabilities and Stockholders' Equity | $ | 2,569,555 | $ | 2,152,309 | |||||||
See accompanying notes to condensed financial statements.
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OTTER TAIL CORPORATION (PARENT COMPANY)
CONDENSED STATEMENTS OF INCOME
| Years Ended December 31, | |||||||||||||||||
| (in thousands) | 2024 | 2023 | 2022 | ||||||||||||||
| Income | |||||||||||||||||
| Equity Income in Earnings of Subsidiaries | $ | 304,525 | $ | 294,467 | $ | 296,833 | |||||||||||
| Interest Income from Subsidiaries | 3,107 | 2,898 | 3,382 | ||||||||||||||
| Other Income | 15,085 | 10,496 | 466 | ||||||||||||||
| Total Income | 322,717 | 307,861 | 300,681 | ||||||||||||||
| Expense | |||||||||||||||||
| Nonelectric Selling, General, and Administrative Expenses | 23,016 | 12,816 | 17,269 | ||||||||||||||
| Interest Expense | 3,599 | 3,813 | 4,066 | ||||||||||||||
| Interest Expense from Subsidiaries | 5 | 6 | 5 | ||||||||||||||
| Nonservice Cost Components of Postretirement Benefits | 970 | 1,063 | 1,023 | ||||||||||||||
| Total Expense | 27,590 | 17,698 | 22,363 | ||||||||||||||
| Income Before Income Taxes | 295,127 | 290,163 | 278,318 | ||||||||||||||
| Income Tax Benefit | 6,535 | 4,028 | 5,866 | ||||||||||||||
| Net Income | $ | 301,662 | $ | 294,191 | $ | 284,184 | |||||||||||
See accompanying notes to condensed financial statements.
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OTTER TAIL CORPORATION (PARENT COMPANY)
CONDENSED STATEMENTS OF CASH FLOWS
| Years Ended December 31, | |||||||||||||||||
| (in thousands) | 2024 | 2023 | 2022 | ||||||||||||||
| Cash Flows from Operating Activities | |||||||||||||||||
| Net Cash Provided by Operating Activities | $ | 76,333 | $ | 77,139 | $ | 28,807 | |||||||||||
| Cash Flows from Investing Activities | |||||||||||||||||
| Investment in Subsidiaries | (55,000) | (40,000) | (50,000) | ||||||||||||||
Purchases of Investments and Other Assets | (53,085) | (1,754) | (3,175) | ||||||||||||||
| Other, net | 1,394 | 1,686 | 1,480 | ||||||||||||||
| Net Cash Used in Investing Activities | (106,691) | (40,068) | (51,695) | ||||||||||||||
| Cash Flows from Financing Activities | |||||||||||||||||
| Net (Repayments) Borrowings on Short-Term Debt | — | — | (22,637) | ||||||||||||||
| Borrowings from Subsidiaries | 179,247 | 148,308 | 236,926 | ||||||||||||||
| Payments for Shares Withheld for Employee Tax Obligations | (6,457) | (3,088) | (2,942) | ||||||||||||||
| Dividends Paid | (78,265) | (73,061) | (68,755) | ||||||||||||||
| Other, net | (729) | (339) | (461) | ||||||||||||||
Net Cash Provided by Financing Activities | 93,796 | 71,820 | 142,131 | ||||||||||||||
| Net Change in Cash and Cash Equivalents | 63,438 | 108,891 | 119,243 | ||||||||||||||
| Cash and Cash Equivalents at Beginning of Period | 228,137 | 119,246 | 3 | ||||||||||||||
| Cash and Cash Equivalents at End of Period | $ | 291,575 | $ | 228,137 | $ | 119,246 | |||||||||||
See accompanying notes to condensed financial statements.
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OTTER TAIL CORPORATION (PARENT COMPANY)
NOTES TO CONDENSED FINANCIAL STATEMENTS
Incorporated by Reference
OTC’s consolidated statements of comprehensive income and common shareholders’ equity in Part II, Item 8 are incorporated by reference.
Basis of Presentation
The condensed financial information of OTC is presented to comply with Rule 12-04 of Regulation S-X. The unconsolidated condensed financial statements do not reflect all of the information and notes normally included with financial statements prepared in accordance with generally accepted accounting principles. Therefore, these condensed financial statements should be read with the consolidated financial statements and related notes included in this report on Form 10-K.
OTC’s investments in subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of the subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded in the balance sheets. The income from operations of the subsidiaries is reported on a net basis as equity income in earnings of subsidiaries.
Related Party Transactions
Outstanding receivables from and payables to OTC's subsidiaries as of December 31, 2024 and 2023 are as follows:
| (in thousands) | Accounts Receivable | Interest Receivable | Current Notes Receivable | Long-Term Notes Receivable | Accounts Payable | Current Notes Payable | |||||||||||||||||||||||||||||
| December 31, 2024 | |||||||||||||||||||||||||||||||||||
| Otter Tail Power Company | $ | 5,223 | $ | — | $ | — | $ | — | $ | 7 | $ | — | |||||||||||||||||||||||
| Northern Pipe Products, Inc. | 36 | 7 | — | 5,000 | — | 66,170 | |||||||||||||||||||||||||||||
| Vinyltech Corporation | — | 17 | — | 11,500 | — | 90,764 | |||||||||||||||||||||||||||||
| BTD Manufacturing, Inc. | — | 78 | — | 52,000 | — | 5,662 | |||||||||||||||||||||||||||||
| T.O. Plastics, Inc. | 42 | 15 | 4,706 | 10,400 | — | — | |||||||||||||||||||||||||||||
| Varistar Corporation | — | — | — | — | — | 590,029 | |||||||||||||||||||||||||||||
| Otter Tail Assurance Limited | 341 | — | — | — | — | — | |||||||||||||||||||||||||||||
Total | $ | 5,642 | $ | 117 | $ | 4,706 | $ | 78,900 | $ | 7 | $ | 752,625 | |||||||||||||||||||||||
| December 31, 2023 | |||||||||||||||||||||||||||||||||||
| Otter Tail Power Company | $ | 2,415 | $ | — | $ | — | $ | — | $ | 7 | $ | — | |||||||||||||||||||||||
| Northern Pipe Products, Inc. | — | 7 | — | 5,000 | — | 56,917 | |||||||||||||||||||||||||||||
| Vinyltech Corporation | 14 | 17 | — | 11,500 | — | 98,016 | |||||||||||||||||||||||||||||
| BTD Manufacturing, Inc. | — | 78 | — | 52,000 | — | 6,291 | |||||||||||||||||||||||||||||
| T.O. Plastics, Inc. | 36 | 15 | — | 10,400 | — | 980 | |||||||||||||||||||||||||||||
| Varistar Corporation | — | — | — | — | — | 406,468 | |||||||||||||||||||||||||||||
| Otter Tail Assurance Limited | 90 | — | — | — | — | — | |||||||||||||||||||||||||||||
Total | $ | 2,555 | $ | 117 | $ | — | $ | 78,900 | $ | 7 | $ | 568,672 | |||||||||||||||||||||||
Dividends
Dividends paid to OTC (the Parent) from its subsidiaries were as follows:
| (in thousands) | 2024 | 2023 | 2022 | ||||||||||||||
| Cash Dividends Paid to Parent by Subsidiaries | $ | 78,191 | $ | 72,982 | $ | 68,680 | |||||||||||
See OTC’s notes to consolidated financial statements in Part II, Item 8 for other disclosures.
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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, 2024, 2023 and 2022:
| (in thousands) | Balance, January 1 | Charged to Cost and Expenses | Deductions(1) | Balance, December 31 | |||||||||||||||||||
| Allowance for Credit Losses | |||||||||||||||||||||||
| 2024 | $ | 2,522 | $ | 1,242 | $ | (1,844) | $ | 1,920 | |||||||||||||||
| 2023 | 1,648 | 2,014 | (1,140) | 2,522 | |||||||||||||||||||
| 2022 | 1,836 | 909 | (1,097) | 1,648 | |||||||||||||||||||
(1)Amounts reflect deductions to the allowance for amounts written-off, net of recoveries. | |||||||||||||||||||||||
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3. Exhibits
The following Exhibits are filed as part of, or incorporated by reference into, this report.
| No. | Description | ||||
| 3.1 | |||||
| 3.2 | |||||
| 4.1 | |||||
| 10.1.0 | |||||
| 10.1.1 | |||||
| 10.1.2 | |||||
| 10.1.3 | |||||
| 10.2 | |||||
| 10.3 | |||||
| 10.4 | |||||
| 10.5 | |||||
| 10.6 | |||||
10.7 | |||||
10.8 | |||||
10.9 | |||||
10.10.0 | Agreement for Sharing Ownership of Generating Plant by and between the Company, Montana-Dakota Utilities Co., and Northwestern Public Service Company (dated as of January 7, 1970). Previously filed as Exhibit 10-F in Form 10-K for the year ended December 31, 1989 | ||||
10.10.1 | 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 | ||||
10.10.2 | 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 | ||||
10.10.3 | 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 | ||||
10.10.4 | 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 | ||||
10.10.5 | |||||
10.10.6 | 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 | ||||
10.11 | |||||
10.12.0 | Agreement for Sharing Ownership of Coyote Station Generating Unit No. 1 by and between the Company, Minnkota Power Cooperative, Inc., Montana-Dakota Utilities Co., Northwestern Public Service Company and Minnesota Power & Light Company (dated as of July 1, 1977). Previously filed as Exhibit 5-H in filing 2-61043 | ||||
10.12.1 | 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 | ||||
10.12.2 | 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 | ||||
10.12.3 | 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 | ||||
10.12.4 | 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 | ||||
10.12.5 | |||||
10.12.6 | |||||
10.13.0 | |||||
95
| No. | Description | ||||
10.13.1 | |||||
10.13.2 | |||||
10.14 | |||||
10.15 | |||||
10.16 | |||||
10.17 | |||||
10.18 | |||||
10.19 | |||||
10.20 | |||||
10.21 | |||||
10.22 | |||||
10.23 | |||||
10.24 | |||||
10.25 | |||||
10.26 | |||||
10.27 | |||||
10.28 | |||||
10.29 | |||||
10.30 | |||||
10.31 | |||||
10.32 | |||||
| 19 | |||||
| 21 | |||||
| 23 | |||||
| 24 | |||||
| 31.1 | |||||
| 31.2 | |||||
| 32.1 | |||||
| 32.2 | |||||
| 97 | |||||
| 101.SCH | Inline XBRL Taxonomy Extension Schema Document | ||||
| 101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document | ||||
| 101.LAB | Inline XBRL Taxonomy Extension Label Linkbase Document | ||||
| 101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document | ||||
| 101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document | ||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | ||||
*Management contract, compensatory plan or arrangement required to be filed pursuant to Item 601(b)(10)(iii)(A) of Regulation S-K.
**Confidential information has been omitted from this Exhibit and filed separately with the Securities and Exchange Commission pursuant to a confidential treatment request under Rule 24b-2.
The Company hereby undertakes to furnish copies of any of the omitted schedules and exhibits to the Securities and Exchange Commission upon request.
Pursuant to Item 601(b)(4)(iii) of Regulation S-K, copies of certain instruments defining the rights of holders of certain long-term debt of the Company are not filed, and in lieu thereof, the Company agrees to furnish copies thereof to the Securities and Exchange Commission upon request.
96
| ITEM 16. | FORM 10-K SUMMARY | ||||
None.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| OTTER TAIL CORPORATION | ||||||||
| By: | /s/ Todd R. Wahlund | |||||||
| Todd R. Wahlund Vice President and Chief Financial Officer (authorized officer and principal financial officer) | ||||||||
| Dated: February 19, 2025 | ||||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:
Signature and Title
| Charles S. MacFarlane | ) | ||||||||||
| President and Chief Executive Officer | ) | ||||||||||
| (principal executive officer) and Director | ) | ||||||||||
| ) | |||||||||||
| Todd R. Wahlund | ) | ||||||||||
| Vice President and Chief Financial Officer | ) | ||||||||||
| (principal financial and accounting officer) | ) | ||||||||||
| ) | By | /s/ Charles S. MacFarlane | |||||||||
| Nathan I. Partain | ) | Charles S. MacFarlane | |||||||||
| Chairman of the Board and Director | ) | Pro Se and Attorney-in-Fact | |||||||||
| ) | Dated: February 19, 2025 | ||||||||||
| Jeanne H. Crain, Director | ) | ||||||||||
| ) | |||||||||||
| John D. Erickson, Director | ) | ||||||||||
| ) | |||||||||||
| Steven L. Fritze, Director | ) | ||||||||||
| ) | |||||||||||
| Kathryn O. Johnson, Director | ) | ||||||||||
| ) | |||||||||||
| Michael E. LeBeau, Director | ) | ||||||||||
| ) | |||||||||||
| Mary E. Ludford, Director | ) | ||||||||||
| ) | |||||||||||
| Thomas J. Webb, Director | ) | ||||||||||
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