ARS 1 a2025annualreportottr_no.htm ARS
Annual Report 2025 S H A R E H O L D E R S E RV I C ES 215 South Cascade Street P.O. Box 496 Fergus Falls, MN 56538 Email: sharesvc@ottertail.com www.ottertail.com | Nasdaq: OTTR O TTER TA IL CO RPO RATIO N 2025 A N N U A L REPO RT

Welcome to our 2025 Annual Report Portfolio Overview Electric Segment Manufacturing Segment Plastics Segment Otter Tail Power Company Electric utility Headquarters: Fergus Falls, MN Founded: 1907 Full-time employees: 726 www.otpco.com BTD Manufacturing, Inc. Metal fabricator Headquarters: Detroit Lakes, MN Acquired: 1995 Full-time employees: 1,075 www.btdmfg.com T.O. Plastics, Inc. Plastic products manufacturer Headquarters: Clearwater, MN Acquired: 2001 Full-time employees: 160 www.toplastics.com Northern Pipe Products, Inc. PVC pipe manufacturer Headquarters: Fargo, ND Acquired: 1995 Full-time employees: 106 www.northernpipe.com Vinyltech Corporation PVC pipe manufacturer Headquarters: Phoenix, AZ Acquired: 2000 Full-time employees: 94 www.vtpipe.com Financial Highlights ‘21‘16 ‘17 ‘18 ‘19 ‘20 ‘22 ‘23 ‘24 ‘25 $7 .0 0 $7 .1 7 $6 .5 5 $4 .2 3 $2 .3 4 $1 .6 0 $1 .8 1 $2 .0 6 $2 .1 7 $6 .7 8 19 .2 % 11 .6 % 11 .6 % 11 .5 % 10 .6 % 25 .6 % 22 .1 % 19 .3 % 15 .6 % 9. 8% ‘21‘16 ‘17 ‘18 ‘19 ‘20 ‘22 ‘23 ‘24 ‘25 ‘21‘20‘19‘18‘17‘16 ‘22 ‘23 ‘24 ‘25 $1 .5 6 $1 .4 8 $1 .4 0 $1 .3 4 $1 .2 8 $1 .2 5 $1 .6 5 $1 .7 5 $1 .8 7 $2 .1 0 Diluted Earnings Per Share Return on Equity Dividends Per Share

Otter Tail Corporation aims to build top-performing companies in a diversified organization for the benefit of our shareholders, customers and employees, and I am proud of what we accomplished in 2025 together. To our shareholders, thank you for your investment. Your ongoing confidence in us and our future allows us to serve our customers well. To our customers, thank you for your continued trust in us. We are honored to serve you. To our employees, you are what fuels our success. Thank you for your efforts, your dedication to our customers and shareholders and for the ways you live out our values each day. STRONG FINANCIAL RESULTS Otter Tail Corporation’s 2025 financial results exceeded our expectations for the year even as our Plastics segment earnings receded from a historic high last year. Collectively, our businesses produced earnings of $276 million, or $6.55 per share, and we generated $386 million of cash from operations. We ended 2025 in a position of financial strength, with a balance sheet capable of funding our customer-focused growth plan without any near-term external equity needs. We produced a utility sector leading return on equity of 16 percent on an equity layer of 63 percent. In early 2026, we increased our dividend by 10 percent, producing an annual indicated dividend of $2.31 per share. This is the second year in a row we announced a double- digit increase to our dividend, reflecting our commitment To our shareholders Charles S. MacFarlane, President and Chief Executive Officer to delivering shareholder value and returning money to shareholders. 2026 will mark the 88th consecutive year Otter Tail Corporation has paid dividends to our shareholders without interruption or reduction. For the fifth year in a row, Otter Tail Corporation received the Edison Electric Institute (EEI) Index Award for the top performing small-capitalization utility with a total shareholder return of 158 percent over the five-year period ending September 30, 2025. Our total shareholder return of 158 percent was the highest of all EEI member companies. DELIVERING ON STRATEGY ELECTRIC SEGMENT HIGHLIGHTS Otter Tail Power Company, our regulated electric utility, produced $98 million of earnings in 2025. We had a full agenda for the year and our team members rose to the occasion. We completed our wind repowering project in early 2026, upgrading the wind towers at four of our owned wind energy centers. These upgrades are expected to result in a 20 percent increase in output, and due to the benefit of renewable energy tax credits, are very economical for our customers. Our two solar developments projects are underway. Our 50 megawatt facility located in Minnesota, Solway Solar, is in the early stages of construction. Abercrombie Solar, our 295 megawatt facility located in North Dakota, remains under development. Solway Solar is expected to be fully operational in late 2026 or early 2027. Abercrombie Solar is currently anticipated to come online in 2028. Our total capital investment associated with these projects is approximately $530 million, and these projects are expected to qualify for full production tax credits. We look forward to adding additional cost-effective solar generation to our portfolio. We continued to make progress on our large regional transmission projects, securing various regulatory approvals and continuing our public outreach efforts. We have a significant amount of regional transmission investment opportunity in the coming years, with nearly $900 million included in our five-year capital spending plan for 2026 through 2030. These projects are expected to have a limited impact on our retail customer bills as most of the cost will be allocated to other Midcontinent Independent System Operator (MISO) customers, generators or new interconnections. These projects will take years to complete but will provide many reliability-related benefits to our customers.

We executed on our key regulatory priorities throughout 2025. We filed rate requests in South Dakota and Minnesota for the first time since 2018 and 2020, respectively. We requested to increase our net revenues by approximately $5.7 million, or 12.5 percent, in South Dakota and $44.8 million, or 17.7 percent, in Minnesota. The increases were primarily driven by customer-focused infrastructure investments and the impact of inflation since our latest rate reviews. Even with the proposed increases, Otter Tail Power will continue to have some of the lowest electric rates in the region and country. We remain committed to providing safe, reliable and low-cost electric service to our customers. Throughout 2025, our team members engaged with companies looking to add new large loads to our system. We have, and will continue to be, thoughtful in our negotiations to appropriately mitigate potential adverse implications of adding new large loads to our existing customer base. Adding new loads, if appropriately managed, would not only benefit us but our existing customers as it enables us to spread out fixed costs. In early 2025, we reached an electric service agreement with a new 155 megawatt load, of which 3 megawatts are firm and 152 megawatts are interruptible. We expect this customer to be fully ramped up in the coming months. We are happy to partner with this unique customer who is bringing energy innovation to the region. MANUFACTURING SEGMENT HIGHLIGHTS Our Manufacturing segment, comprised of BTD Manufacturing, our contract metal fabricator, and T.O. Plastics, our plastic products manufacturer, generated $12 million of earnings in 2025. Our manufacturing businesses continued to face soft end market demand, following a sharp decline in sales volumes beginning in the third quarter of 2024. Our team members did an excellent job aligning our cost structure with the current demand environment to mitigate the impact of lower sales volumes on earnings. We saw the benefit of these efforts in the second half of the year. We completed the expansion of our BTD Georgia location in early 2025. Many of our customers are growing or are expected to grow in the southeastern part of the U.S. This strategic expansion will allow us to better serve and grow with these customers in the years to come. Despite the continued down-cycle, we remain well positioned to respond when conditions improve. This segment continues to produce incremental cash to fund our customer-focused growth plan and its long-term fundamentals remain intact. PLASTICS SEGMENT HIGHLIGHTS Northern Pipe Products and Vinyltech, our two PVC pipe manufacturing companies comprising our Plastics segment, produced $170 million of earnings in 2025. Our team members navigated dynamic market conditions throughout 2025. Our sales prices of PVC pipe continued to recede from peak levels, with some quarters experiencing more rapid rates of decline. Conversely, the cost of PVC resin, our primary input, remained relatively low due to an increased global supply. Sales volumes also remained strong in 2025. We benefitted from the incremental production capacity added at Vinyltech in late 2024. We expect to complete the second phase of our Vinyltech expansion project in early 2026 and look forward to bringing this additional capacity online. Once our multi-phase expansion project is complete, our total annual nameplate production capacity for our Plastics segment will increase by approximately 50 million pounds, or 15 percent. This new capacity will allow us to better serve our customers in the southwestern part of the U.S. and capitalize on demand trends in this market. EXCITEMENT FOR THE FUTURE We are excited about the growth opportunities across our portfolio. Otter Tail Power’s 2026 to 2030 capital investment plan is robust, totaling $1.9 billion over this time period. We expect this plan to produce a rate base compounded annual growth rate of 10 percent. Our long-term earnings per share growth rate is seven to nine percent, resulting in a targeted shareholder return of 10 to 12 percent. Our long-term earnings mix target is 70 percent Electric and 30 percent Manufacturing and Plastics. The fundamentals of our businesses remain strong and we are confident in our ability to deliver on our customer- focused growth plan. Thank you again to our employees for all you accomplished in 2025 and to our customers and shareholders for your continued confidence in Otter Tail Corporation. Charles S. MacFarlane President and Chief Executive Officer

CHARLES S. MACFARLANE President and Chief Executive Officer TODD R. WAHLUND Vice President and Chief Financial Officer JENNIFER O. SMESTAD Senior Vice President General Counsel and Corporate Secretary TIMOTHY J. ROGELSTAD Senior Vice President Electric Platform President, Otter Tail Power Company JOHN S. ABBOTT Senior Vice President Manufacturing Platform President, Varistar PAUL L. KNUTSON Vice President Human Resources STEPHANIE A. HOFF Director Corporate Communications Executive and Senior Leadership NATHAN I. PARTAIN Chairman of the Board Retired President and Chief Investment Officer Duff & Phelps Investment Management Co. CHRISTOPHER B. CLARK 1,3 Retired President Northern States Power Company Xcel Energy Inc. JEANNE H. CRAIN 1,2 Retired President and Chief Executive Officer Bremer Financial Corporation JOHN D. ERICKSON Advisor Former President and Chief Executive Officer Otter Tail Corporation STEVEN L. FRITZE 1,3 Retired Chief Financial Officer Ecolab Inc. DR. KATHRYN O. JOHNSON 2,3 Senior Geochemist Barr Engineering DR. MICHAEL E. LEBEAU 2,3 System Vice President Sanford Health MARY E. LUDFORD 1,3 Retired Chief Audit Executive and Deputy Chief Security Officer Exelon Corporation CHARLES S. MACFARLANE President and Chief Executive Officer Otter Tail Corporation STEVEN P. RASCHE 1,2 Retired Executive Vice President and Chief Financial Officer Spire Inc. THOMAS J. WEBB 1,2 Advisor Retired Executive Vice President and Chief Financial Officer CMS Energy Corporation Directors Board Committees 1. Audit 2. Compensation and Human Capital Management 3. Corporate Governance

Five-Year Financial Summary $ in thousands, except per share amounts and share data Financial Results 2025 2024 2023 2022 2021 Operating Revenues Electric Segment $ 566,756 $ 524,515 $ 528,359 $ 549,699 $ 480,321 Manufacturing Segment 314,547 342,592 402,781 397,983 336,294 Plastics Segment 422,755 463,441 418,026 512,527 380,229 Total Operating Revenues $ 1,304,058 $ 1,330,548 $ 1,349,166 $ 1,460,209 $ 1,196,844 Net Income Electric Segment $ 97,586 $ 90,963 $ 84,424 $ 79,974 $ 72,458 Manufacturing Segment 11,517 13,681 21,454 20,950 17,186 Plastics Segment 170,400 200,747 187,748 195,374 97,823 Corporate (3,610) (3,729) 565 (12,114) (10,698) Total Net Income $ 275,893 $ 301,662 $ 294,191 $ 284,184 $ 176,769 Diluted Earnings Per Share $ 6.55 $ 7.17 $ 7.00 $ 6.78 $ 4.23 Cash Flow from Operations $ 385,985 $ 452,731 $ 404,499 $ 389,309 $ 231,243 Capital Expenditures Electric Segment $ 270,593 $ 301,454 $ 240,695 $ 147,869 $ 140,031 Total Capital Expenditures $ 288,068 $ 358,650 $ 287,134 $ 171,134 $ 171,829 Financial Position Assets Electric Segment $ 3,006,695 $ 2,785,522 $ 2,533,831 $ 2,351,961 $ 2,283,776 Total Assets $ 3,964,279 $ 3,652,082 $ 3,242,568 $ 2,901,661 $ 2,754,830 Total Debt $ 1,103,759 $ 1,013,349 $ 905,481 $ 832,025 $ 855,160 Total Equity $ 1,861,760 $ 1,668,499 $ 1,443,006 $ 1,217,317 $ 990,777 Capitalization ratios Debt 37.2% 37.8% 38.6% 40.6% 46.3% Equity 62.8% 62.2% 61.4% 59.4% 53.7% Other Total Return (Share Price Appreciation plus Dividends) 12.3% (10.9)% 47.7% (15.5)% 71.3% Return on Equity (1) 15.6% 19.3% 22.1% 25.6% 19.2% Dividends Per Share $ 2.10 $ 1.87 $ 1.75 $ 1.65 $ 1.56 Dividend Payout Ratio 32.1% 26.1% 25.0% 24.0% 37.0% Number of Common Shares Outstanding 41,905,520 41,827,967 41,710,521 41,631,113 41,551,524 Closing Stock Price $ 80.81 $ 73.84 $ 84.97 $ 58.71 $ 71.42 Market Capitalization $ 3,389,609 $ 3,088,577 $ 3,544,143 $ 2,444,163 $ 2,967,610 Book Value Per Share $ 44.43 $ 39.89 $ 34.60 $ 29.24 $ 23.84 Notes: (1) Earnings available for common shares divided by the 13-month average of month-end common equity balances.

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, 2025 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, P.O. 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, 2025, the aggregate market value of common stock held by non-affiliates was $3,126,792,910. Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date: 41,953,525 Common Shares ($5 par value) as of February 12, 2026. DOCUMENTS INCORPORATED BY REFERENCE The Registrant's definitive Proxy Statement for its 2026 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS Description Page Definitions 2 Where to Find More Information 3 Forward-Looking Information 3 PART I ITEM 1. Business 4 ITEM 1A. Risk Factors 19 ITEM 1B. Unresolved Staff Comments 27 ITEM 1C. Cybersecurity 27 ITEM 2. Properties 29 ITEM 3. Legal Proceedings 30 ITEM 3A. Information About Our Executive Officers (as of February 18, 2026) 30 ITEM 4. Mine Safety Disclosures 31 PART II ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 31 ITEM 6. [Reserved] 31 ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 31 ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk 45 ITEM 8. Financial Statements: Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34) 46 Consolidated Balance Sheets 48 Consolidated Statements of Income 49 Consolidated Statements of Comprehensive Income 50 Consolidated Statements of Shareholders’ Equity 51 Consolidated Statements of Cash Flows 52 Notes to Consolidated Financial Statements 53 ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 84 ITEM 9A. Controls and Procedures 84 ITEM 9B. Other Information 85 ITEM 9C. Disclosure Regarding Foreign Jurisdictions That Prevent Inspections 85 PART III ITEM 10. Directors, Executive Officers and Corporate Governance 86 ITEM 11. Executive Compensation 86 ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 86 ITEM 13. Certain Relationships and Related Transactions, and Director Independence 86 ITEM 14. Principal Accountant Fees and Services 87 PART IV ITEM 15. Exhibits and Financial Statement Schedules 88 ITEM 16. Form 10-K Summary 96 Signatures 97 1

DEFINITIONS The following abbreviations or acronyms are used in the text: 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 MATS Mercury and Air Toxics Standards ASC Accounting Standards Codification MDT Metering and Distribution Technology BSER Best System of Emission Reduction MISO Midcontinent Independent System Operator BTD BTD Manufacturing, Inc. MPUC Minnesota Public Utilities Commission CCMC Coyote Creek Mining Company, L.L.C. MW Megawatt CCR Coal Combustion Residual NAV Net Asset Value CDD Cooling Degree Day NDDEQ North Dakota Department of Environmental Quality CIS Center for Information Security NDPSC North Dakota Public Service Commission CO2 Carbon dioxide NERC North American Electric Reliability Corporation CODM Chief Operating Decision Maker Northern Pipe Northern Pipe Products, Inc. COSO Committee of Sponsoring Organizations of the Treadway Commission OBBBA One Big Beautiful Bill Act DOE U.S. Department of Energy OEMs Original Equipment Manufacturers DOJ U.S. Department of Justice OTC Otter Tail Corporation ECO Energy Conservation and Optimization Rider OTP Otter Tail Power Company EEI Edison Electric Institute PIR Phase-in Rider EEP Energy Efficiency Plan PSLRA Private Securities Litigation Reform Act of 1995 EPA Environmental Protection Agency PTCs Production tax credits ERISA Employee Retirement Income Security Act of 1974 PVC Polyvinyl chloride ESSRP Executive Survivor and Supplemental Retirement Plan RHR Regional Haze Rule EUIC Electric Utility Infrastructure Costs Rider ROE Return on equity FASB Financial Accounting Standards Board REC Renewable Energy Certificate FCA Fuel Clause Adjustment RRR Renewable Resource Rider FERC Federal Energy Regulatory Commission RTOs Regional Transmission Organizations FOB Free on Board SDPUC South Dakota Public Utilities Commission GCR Generation Cost Recovery Rider SEC Securities and Exchange Commission GHG Greenhouse Gas SIP State Implementation plan HDD Heating Degree Day SO2 Sulfur Dioxide HDPE High-Density Polyethylene SOFR Secured Overnight Financing Rate ICSP Information and Cybersecurity Program SPP Southwest Power Pool IRP Integrated Resource Plan T.O. Plastics T.O. Plastics, Inc. IT Information Technology TCR Transmission Cost Recovery Rider ITC Investment Tax Credits TSR Total Shareholder Return JTIQ Joint Targeted Interconnection Queue VIE Variable Interest Entity kV kiloVolt Vinyltech Vinyltech Corporation 2

WHERE TO FIND MORE INFORMATION We make available free of charge on our website (www.ottertail.com) our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy and information statements, Forms 3, 4 and 5 filed on behalf of directors and executive officers and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (SEC). These reports are also available on the SEC's website (www.sec.gov). Information on our and the SEC's websites is not deemed to be incorporated by reference into this report on Form 10-K. FORWARD-LOOKING INFORMATION This report on Form 10-K contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 (the PSLRA). When used in this Form 10-K and in future filings by the Company with the SEC, in the Company’s press releases and in oral statements, words such as “anticipate,” “believe,” "can," “could,” “estimate,” “expect,” "future," "goal," “intend,” "likely," “may,” “outlook,” “plan,” "positions," “possible,” “potential,” "predict," "probable," "projected," “should,” "target," “will,” “would” or similar expressions are intended to identify forward-looking statements within the meaning of the PSLRA. Such statements are based on current expectations and assumptions and entail various risks and uncertainties that could cause actual results to differ materially from those expressed in such forward-looking statements. Such risks and uncertainties include the various factors set forth in Item 1A. Risk Factors of this report on Form 10-K and in our other SEC filings. 3

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. Our corporate offices are 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, serves approximately 134,000 customers in more than 400 communities across a predominantly rural and agricultural service territory. Manufacturing consists of businesses which provide metal fabrication services and manufacture thermoformed plastic products. 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 primarily used in municipal water infrastructure 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 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 driven by planned investments in our Electric segment and complemented by our strategic diversification. Otter Tail Power, our foundational business dating back to 1907, is a high-performing electric utility with a robust five-year capital investment and growth plan. Our electric operations are complemented by the long-term ownership of our Manufacturing and Plastics segment businesses (collectively, our Manufacturing Platform). Our strategic diversification positions us to provide earnings, cash flow and dividend growth over long-term investment and economic cycles, and to produce shareholder returns above the utility industry average. We drive growth through rate base investments in our Electric segment and organic growth opportunities in our Manufacturing Platform. We are able to efficiently redeploy cash generated by our Manufacturing Platform to finance our Electric segment investments. Our strategy and risk profile are designed to provide a predictable earnings stream, investment grade credit ratings and continuous 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 7 to 9%, with a long-term earnings mix target of approximately 70% from our Electric segment and 30% 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 recent investments within our Manufacturing and Plastics segments. Since 2021, our earnings mix has diverged from our long-term target of 70% from our Electric segment and 30% 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 regularly review our business portfolio to identify additional opportunities to improve our earnings and cash flow generation profile, reduce 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 4

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 long-term strategy and risk profile. 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, 2025 and 2024 along with an historical average and long-term expectation are shown below: Earnings Mix 70% 30% 35% 70% 30% 70% 65% 30% Electric Manufacturing & Plastics (and unallocated corporate costs) 2016 - 2020 Average 2024 2025 Long-Term Expectation 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 2025 Total Recordable Incident Rate was 1.60, compared to 1.64 in 2024 and our Lost Time Incident Rate was 0.52 in 2025, compared to 0.16 in 2024. 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. 5

Inclusive Workplace - We hold every employee accountable for their behavior in maintaining a workplace free of discrimination and harassment. We have implemented educational initiatives for all employees aimed at inclusive leadership and a respectful workplace. 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, 2025, we employed 2,198 full-time employees as shown in the table below: Segment/Organization Employees Electric Segment OTP (1) 726 Manufacturing Segment BTD 1,075 T.O. Plastics 160 Segment Total 1,235 Plastics Segment Northern Pipe 106 Vinyltech 94 Segment Total 200 Corporate 37 Total 2,198 (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, 2025, 378 employees of OTP were represented by local unions of the International Brotherhood of Electrical Workers under two separate collective bargaining agreements expiring on August 31, 2026 and October 31, 2026. None of the employees of our other operating companies are represented by local unions. ELECTRIC Contribution to Operating Revenues: 43% (2025), 39% (2024), 39% (2023) 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 2025 two customers combined accounted for 16% of segment operating revenues. The following charts summarize our retail electric revenues by state and by customer segment for the years ended December 31, 2025 and 2024: Retail Revenue by State 47.8% 48.1% 42.2% 42.9% 10.0% 9.0% Minnesota North Dakota South Dakota 2025 2024 Retail Revenue by Customer Segment 69.2% 68.8% 29.1% 29.4% 1.8% 1.8% Commercial & Industrial Residential Other 2025 2024 6

In addition to retail revenues, our Electric segment also generates operating revenues from the transmission of electricity for others over the transmission assets we wholly or jointly own, and from the sale of electricity we generate and sell into the wholesale electricity market. COMPETITIVE CONDITIONS Our utility business operates as a regulated monopoly. Our retail customers reside within our assigned service territories, and most retail customers do not have the ability to choose their electric supplier. However, we are subject to extensive regulation, as further described below, along with certain public policies that promote competition and development of energy markets. 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 2025, our summer residential rates were 19% below the regional average and 34% 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, 2025 and 2024: Revenue per kwh 2025 2024 Residential 11.23 ¢ 11.38 ¢ Commercial & Industrial 7.27 ¢ 7.03 ¢ Total Retail 8.18 ¢ 7.98 ¢ 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 regulations. 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 or legal challenges 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 uses its own generation facilities to supply energy to customers and supplements this with power purchase agreements. To balance supply and demand, OTP also buys and sells electricity on the wholesale market as needed. The decision to use either owned generation or wholesale market energy depends on current market prices and the cost-effectiveness of each source. Wholesale energy is used when it offers a benefit to customers. 7

As of December 31, 2025, OTP’s wholly or jointly owned plants and facilities, as well as in place power purchase agreements, and their nameplate capacity were: Capacity / Purchased Power in kW (Nameplate Rating) Owned Generation: Baseload Plants Big Stone Plant(1) 256,025 Coyote Station(2) 149,450 Total Baseload Plants 405,475 Combustion Turbine and Small Diesel Units Astoria Station 245,000 Solway 44,500 All Other 72,208 Total Combustion Turbine and Small Diesel Units 361,708 Owned Wind Facilities Merricourt 150,000 Ashtabula III 62,400 Luverne 49,500 Ashtabula 48,000 Langdon 40,500 Total Owned Wind Facilities 350,400 Hoot Lake Solar 49,900 Hydroelectric Facilities 3,870 Total Owned Generation Capacity 1,171,353 Power Purchase Agreements: Purchased Wind Power (greater than 2,000 kW) Edgeley 21,000 Langdon 19,500 Total Purchased Wind 40,500 Total Generating Capacity 1,211,853 (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 nameplate capacity by source, including owned and jointly owned facilities and through power purchase arrangements, as of December 31, 2025 and 2024: December 31, 2025 Coal, 33% Natural Gas & Oil, 30% Owned/Purchased Renewable, 37% December 31, 2024 Coal, 33% Natural Gas & Oil, 33% Owned/Purchased Renewable, 34% 8

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 7.9% and 25.3%, depending on the season. The following charts summarize the percentage of retail kwh sold by source during the years ended December 31, 2025 and 2024: Year Ended December 31, 2025 Coal, 29% Natural Gas & Oil, 7% Owned/Purchased Renewable, 23% Market Energy, 41% Year Ended December 31, 2024 Coal, 26% Natural Gas & Oil, 8% Owned/Purchased Renewable, 23% Market Energy, 43% Our sources of energy to serve our retail customers include energy from our owned or contracted generation plus energy acquired through the wholesale market. Market energy is purchased to meet customer demand when energy from our owned and contracted generation is insufficient or when market prices are lower than our internal production cost and therefore it is more economical to serve our customers with wholesale energy. Capacity and Storage Additions As part of our investment plan to meet our future energy needs, the following projects were recently completed or are currently under development or construction: Wind Energy Facility Upgrades consisted of the replacement or 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. We expect the increased energy production from these facilities after the recently completed upgrades will be equivalent to an additional 40 megawatts (MW) of generation. Following the completion of these upgrades, the energy production from each of these facilities became eligible for production tax credits (PTCs) over a ten-year period. We expect these projects will lower customer costs through a combination of fuel and purchased power savings and the tax credit benefits afforded to our customers. Solway Solar is a solar facility currently under construction and located 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 or early 2027. OTP's capital investment is estimated to be approximately $80 million. We expect the energy production from this facility will be eligible for PTCs over a ten-year period. The costs of this project will be allocated to customers in Minnesota and South Dakota and have been approved for recovery subject to certain terms and conditions. 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. The acquisition of these assets was completed in January 2026, and we currently 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 approximately $450 million. We anticipate the energy production from this facility will be eligible for PTCs over a ten-year period. The costs of this project will be allocated to customers in Minnesota and South Dakota and have been approved for recovery subject to certain terms and conditions. Hoot Lake Battery Energy Storage System is a battery storage project currently under development located near our Hoot Lake Solar facility in Minnesota. Once complete, the facility is expected to have a storage capacity of 75 MW and a storage duration of four hours. OTP's capital investment in the project is estimated to be approximately $120 million, and we expect the project to qualify for a 40% investment tax credit upon completion. The costs of this project have been deemed eligible for rider recovery in Minnesota. We currently expect the facility will be operational in 2028. 9

ENERGY TRANSITION OTP is committed to providing reliable and affordable electric service to its customers while transitioning to a lower-carbon and increasingly clean energy future. We are intent on satisfying the public policy priorities of each jurisdiction in which we operate, including renewable and clean energy milestones applicable in certain of our state jurisdictions. The energy transition of our generation portfolio includes historical and planned future investments in renewable generation, including wind and solar facilities, the planned investment in a battery storage facility, and the retirement of our two remaining co- owned coal generation facilities. From 2005 through 2025, we added 420 MW of owned or contracted renewable generation to our portfolio. We anticipate adding an additional 345 MW of owned renewable solar generation to our portfolio between 2026 and 2028, and we are analyzing the potential for up to an additional 200 MW of owned or contracted wind generation by 2029. In addition, we anticipate adding 75 MW of battery storage by 2028 to complement our renewable generation portfolio. Finally, we currently anticipate closing our two co- owned coal generation facilities in the 2040s upon reaching the end of their operating lives. The transition of our energy generation portfolio has reduced our carbon dioxide (CO2) emissions from our owned generation portfolio by approximately 35% from 2005 to 2025. We are targeting to reduce our CO2 emissions from our owned generation portfolio by 90% by 2050 from 2005 levels. In 2025, we modified our 2050 carbon reduction goal, previously a targeted 97% reduction from 2005 levels, and eliminated our 2030 goal in recognition of the evolving energy landscape. Our near-term carbon emission levels are significantly impacted by many external factors, including regional energy demand, market energy prices, actual and planned retirements of baseload energy generation within our region, and other factors. As a result, it is difficult to predict with reasonable certainty the operating levels of our baseload and peaking generation facilities and resulting CO2 emissions. RESOURCE MATERIALS Coal is the principal fuel burned at our jointly owned Big Stone Plant 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. The supply agreement expires in 2040 but does provide for early termination under certain circumstances and with requirements to fulfill certain obligations. 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, 2025, 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 Investments As a utility and transmission owner operating as a member within MISO, we are participating in large transmission investments intended to improve system reliability and resilience, to promote a cost-effective regional and interregional transmission system, 10

and to allow new generating capacity to access the electric grid. The following projects are in various stages of planning and development or construction: 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. The following is a brief overview of the two projects included in Tranche 1.0: 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. We continue project planning and development and expect material procurement and construction to commence in 2026. The project is expected to be completed in 2029. Big Stone South-Alexandria-Big Oaks includes the construction of a new 345 kV transmission line in eastern South Dakota and western Minnesota and the addition of a second circuit to an existing 345 kV line in central Minnesota. The new transmission line will span approximately 100 miles between Big Stone, South Dakota and Alexandria, Minnesota. A second circuit will be added to the existing transmission line spanning from Alexandria, Minnesota to Big Oaks, Minnesota. We continue project planning and development. Line construction on the second circuit has commenced. We expect construction to commence on the Big Stone South-Alexandria portion of the line in 2028. The project is expected to be completed in 2030. 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, OTP will be a partial owner of three projects, including the addition of a second circuit to an existing 345 kV transmission line, a new 345 kV transmission line, and a new 765 kV transmission line. These projects will be developed and constructed over several years, and OTP's total investment in these projects is currently estimated to be $800 million to $1.0 billion. The following is a brief overview of the three projects included in Tranche 2.1: 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, as well as upgrades to an existing 230 kV line and substation. This project is in the initial stages of 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 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 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. Bison-Hankinson-Big Stone South is a two-part new transmission line project. OTP is 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 Mapleton, North Dakota. These projects, which are expected to be completed in 2034, are in the early stages of development. The U.S. Department of Energy (DOE) has approved a grant to partially fund the construction of these projects 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 currently estimated to be $450 to $500 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 11

and depreciation rates of our capital investments. Decisions by our regulators significantly impact our operating results, financial position and cash flows. Below is a summary of the regulatory agencies with jurisdiction over OTP and the areas of regulation covered by each 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 (5,000 kW or more for wind generating facilities; 50,000 kW or more for non-wind generating facilities) and routes for transmission lines (100 kV or more and exceeding 1,500 feet). Certificates of Need for generating plants and transmission assets. 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 (exceeding 500 kW for wind generating facilities; exceeding 50,000 kW for non-wind generating facilities) and high voltage transmission lines (exceeding 115 kV). Certificates of Convenience and Necessity for service territory expansions. 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 (exceeding 115 kV). Federal Energy Regulatory Commission (FERC) Wholesale electricity sales, the transmission and sale of electric energy in interstate commerce, interconnection of facilities to the interstate transmission system, certain mergers and acquisitions, and corporate transactions, 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. 12

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 the significant 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 services 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) every two years. An IRP is a set of resource options a utility could use to meet the service needs of its customers over the forecast period, including an explanation of the utility’s supply and demand circumstances, and the extent to which each resource option would be used to meet those service needs. The MPUC’s findings of fact and conclusions regarding IRPs are considered to be prima facie evidence, subject to rebuttal, in future rate reviews and other proceedings. OTP will file their next IRP in Minnesota in 2026. Under North Dakota law, utilities are required to submit a 15-year advance IRP every three years for approval by the North Dakota Public Service Commission (NDPSC). OTP will file their next IRP in North Dakota in 2027. 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 December 12, 2025, allows for an equity-to-total-capitalization ratio between 46.7% and 57.1%, with total capitalization not to exceed $2.4 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 solar, 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. We were in compliance with the 2025 target established by the standard, and we plan to comply with the future requirements of this standard through a combination of our existing and projected renewable generation fleet. 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 13

solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 40 kW or less. We met the overall solar requirement in 2025, with a combination of owned solar generation and solar renewable energy certificate (REC) purchases, but we were not compliant with the requirement that 10% of the 1.5% be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 40 kW or less. Minnesota Clean Energy Law Minnesota's Clean Energy Law 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, 2025, OTP invested approximately $6.3 million in environmental control equipment, including $1.9 million in 2025. Our capital budget for the next five years includes approximately $9.3 million of capital investments in environmental control equipment. The timing and amount of our expenditures may change as the regulatory environment changes. Emerging 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. RHR compliance is to be monitored through several implementation periods, the second of which 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. As part of its partial disapproval, the EPA found that North Dakota failed to submit a long- 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 and sulfur dioxide emission controls. Having disapproved, in part, the North Dakota SIP, the EPA 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. In March 2025, the EPA announced it would begin restructuring the RHR to streamline requirements for states, and on April 30, 2025, the EPA granted a request to reconsider the December 2024 partial disapproval of the North Dakota SIP. At this time, the final resolution of regional haze compliance in North Dakota, and specifically the impact, if any, on the operations of Coyote Station is uncertain. Clean Air Act. In May 2024, the EPA finalized new regulations under Section 111 of the Clean Air Act to regulate greenhouse gas (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 14

coal-fired power plants anticipated to be operated after January 2032 but planned 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. Following the issuance of the new regulations, several states and industry groups filed lawsuits challenging the regulation, arguing the EPA overstepped its authority under the Clean Air Act. In June 2025, the EPA published a proposed rule that would repeal the existing GHG emission standards for fossil fuel-fired power plants. The proposal includes a finding that GHG emissions from such sources do not significantly contribute to dangerous air pollution, which the EPA asserts is a necessary legal predicate for regulation under the Clean Air Act. As an alternative, the EPA is also proposing to repeal only the emission guidelines applicable to existing fossil fuel-fired steam generating units. The proposed rule has not yet been finalized. Coal Combustion Residual (CCR) Regulation. In May 2024, the EPA published a final rule amending CCR regulations, which introduced 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. In 2025, the EPA proposed several delays for coal ash disposal and plant closure requirements to address electric grid reliability concerns. We anticipate we may incur costs related to coal ash removal and groundwater monitoring in the future as a result of the amended regulation. We continue to review and evaluate the overall impact this regulation may have on our business, including potential impacts on our operating results, financial condition and liquidity. Mercury and Air Toxics Standards (MATS). In May 2024, the EPA published final regulations to strengthen and update MATS for coal-fired power plants, tightening the emission standards for both particulate matter and for mercury from existing lignite-fired sources. Currently, OTP's coal-fired power plants would be required to comply with these regulations in 2029. However, in June 2025, the EPA published a proposed rule to repeal the May 2024 MATS for coal-fired power plants. Multiple environmental organizations have filed legal challenges to the proposed rule. These legal challenges remain pending but are currently held in abeyance while the EPA undertakes its reconsideration of the MATS amendments. We continue to review and evaluate the overall impact this regulation may have on our business, including potential impacts on our operating results, financial condition and liquidity. Climate Change and Greenhouse Gas Regulation Global climate change presents a significant energy and environmental policy challenge. Combustion of fossil fuels for the generation of electricity is a considerable source of CO2 emissions, which is the primary GHG emitted by our utility operations. The federal government, state governments and international organizations have periodically pursued, and may continue to pursue, climate policies to regulate GHG emissions as part of a broad-based effort to limit global warming. The implementation of climate change programs, such as the Minnesota Clean Energy Law, regulations under the Clean Air Act, if not repealed, and other existing or future federal or state regulations targeting GHG emissions, may have a significant impact on our utility business. MANUFACTURING Contribution to Operating Revenues: 24% (2025), 26% (2024), 30% (2023) Our Manufacturing businesses are engaged in the production of metal or plastics parts and products sold to commercial customers. The following is a brief description of each of these businesses: BTD Manufacturing, Inc. (BTD), founded in 1979 and acquired by Otter Tail Corporation in 1995, provides metal fabrication services for custom machine parts and metal components through its facilities in Detroit Lakes and Lakeville, Minnesota, Washington, Illinois and Dawsonville, Georgia. T.O. Plastics, Inc. (T.O. Plastics), founded in 1948 and acquired by Otter Tail Corporation in 2001, manufactures thermoformed plastics products, including horticulture containers and custom packaging for medical and industrial markets through its facilities in Otsego and Clearwater, Minnesota. OVERVIEW BTD is a value-added metal fabricator that produces custom machine parts and metal components for its original equipment manufacturer (OEM) customers. Through our manufacturing facilities in Minnesota, Illinois, and Georgia, with more than a million square feet of manufacturing capacity, we provide a comprehensive suite of capabilities to produce highly engineered metal parts and components to serve our OEM customers. Our metal fabrication services include: Research and development resources to design and produce product prototypes quickly and cost-effectively; 15

Tool design and construction specializing in both short- and long-run tooling, providing cost effective tools tailored to customer specifications; Fabrication and welding including advanced fabrication and welding, including robotic welding, using the latest technologies to deliver high-quality products; Stamping is the cornerstone service of our business, with presses ranging from 45 to 800 tons, providing cost-effective solutions and flexible options for short and long production runs; Tubing including precise forming and bending operations to manufacture tubular products tailored to customer requirements; Assembly capabilities to provide a full-service experience for our customers; Finishing and painting services including liquid primers and powder coating to meet customer specifications; and Inventory management services include warehousing, packaging, kitting and product sequencing to ensure we deliver the right products to our customers when they need them. Through these capabilities, BTD manufacturers over 30,000 unique parts, including products ranging from welded frames and chassis, roll cages, heat shields, support brackets, handles and railings, and tube and pipe components. Our facilities are ISO 9001:2015 certified, which is the international standard for quality management systems. Our strategy emphasizes utilizing the above set of capabilities from development through inventory management to provide highly engineered metal parts and components at a competitive cost. Leveraging our engineering expertise and technical proficiency, BTD creates value during the entire development, manufacturing and logistics cycle. T.O. Plastics provides custom and proprietary thermoforming solutions for the horticulture, medical, industrial and various other markets. Our proprietary horticulture products are manufactured through a vertically integrated process of raw material pelletizing, extrusion and thermoforming to produce plastic products that serve the early-growth horticulture market. Our proprietary products include round and square pots, plug, carrying and specialty trays, propagation sheets and various other products used in the germination and early growth horticulture industry. The applications for our products include greenhouses and nurseries, microgreen development and vertical farming. T.O. Plastics also provides custom thermoformed plastic packing and parts to serve customers in the medical, industrial, recreational, electronic and other markets. We offer a full suite of capabilities including design, prototyping, tooling construction and thermoforming production to meet our customers' packaging and other plastic parts needs. Our products include various medical device packaging, shipping trays, laboratory trays, housing enclosures and consumer packaging. Both our Clearwater and Otsego facilities in Minnesota are ISO 9001:2015 certified. In addition, our Otsego facility is certified under ISO 13485:2016, which is the international standard for quality management systems in the design and manufacture of medical devices. In addition, we maintain two Class 8 cleanrooms at our Otsego facility used in the production of plastic packaging and parts for the medical industry. Our strategy is focused on producing horticulture products through our integrated manufacturing capabilities to deliver high-quality products at a competitive cost. We also strive to provide custom plastics packaging and parts to our medical and industrial customers through our end-to-end service offering from discovery and design to tooling and manufacturing while meeting all customer product specifications. CUSTOMERS Our metal fabrication business primarily serves OEMs operating in the Midwest and Southeastern U.S. The primary end markets we serve include recreational vehicle (powersports), lawn and garden, agricultural, construction, industrial, energy equipment and certain other markets. Our customers include some of the largest vehicle and equipment manufacturers operating in the U.S., including Caterpillar Inc., CNH Industrial N.V., Cummins Inc., Deere & Company, Honda Motor Co., Kawasaki Heavy Industries, Polaris Inc. and The Toro Company. We have developed long-standing business relationships with our OEM customers, many of which span decades. In many cases, we are an integral component of our customers' supply chains and strive to maintain strong strategic alignment. We have not historically experienced high rates of customer attrition given high customer switching costs resulting from our embedded relationships driven by our broad capabilities and scale. The principal method of product distribution is by direct shipment to our customers through direct customer pick-up or common carrier ground transportation. 16

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 custom packaging and other plastic products are manufactured to customer specifications and sold to other manufacturers or end customers. The following presents our revenue by end market for each of the five years ended December 31: End Market Sales (% of Sales) 29% 30% 30% 32% 31% 15% 15% 19% 19% 20% 13% 16% 16% 15% 12% 18% 16% 13% 10% 8% 11% 9% 10% 13% 15% 10% 10% 8% 7% 8% 4% 4% 4% 4% 6% Other Horticulture Industrial Lawn & Garden Agriculture Construction Rec. Vehicle 2021 2022 2023 2024 2025 Although we sell our products to a large number of customers across a diverse group of end markets, three customers combined to account for approximately 44% of segment operating revenues in 2025. COMPETITIVE CONDITIONS The metal fabrication market is highly fragmented with competition primarily from domestic entities. Most competition is comprised of privately owned small-scale fabrication shops that specialize in a single or limited set of production capabilities or focus on certain end markets or geographical service territories. Some larger competitors bring broad manufacturing capabilities and greater geographical reach. Competition can be geographically regionalized as customers procure products locally to manage costs and minimize logistical complexities. Competitive dynamics we face within the industry include breadth of product offerings, competitive cost structures and product pricing, and manufacturing capacity and distribution capabilities. BTD competes on its full breadth of value-add services from research and development, to tool and die design and manufacturing, to its full suite of fabrication and machining capabilities, and its finishing services and inventory management capabilities. Our end-to- end solution reduces customer logistics burden, compresses cycle times and improves quality. We have invested in automation and robotics to improve productivity, increase process repeatability, manage skilled labor constraints and enhance product quality. The diversity of end markets BTD serves, its full suite of manufacturing capabilities, and its geographical reach from the Midwest to the Southeast of the U.S. provides resilience against fluctuations in individual sector or geographical demand. When demand shifts, we can adapt by reallocating production to align with changing conditions. The plastic thermoforming market for horticultural products is highly fragmented with competition from domestic and international entities. Our competitors vary in size, production capabilities, geographical reach and customer focus. Competition varies by sales channel, with some competitors primarily selling through horticulture focused distribution, while other competitors implement a direct sales strategy to the horticulture grower customer. Low-cost import competition from Southeast Asia has expanded with these competitors primarily targeting the direct to grower sales channel. Competition in the custom plastic packaging and parts industry is highly fragmented with competition from domestic and international entities. Many competitors are larger in size with greater manufacturing capabilities and geographical reach. Overall, the principal competitive factors in our Manufacturing segment are product quality, price competitiveness, breadth of product line and customer service. We intend to continue to compete based on high-quality products, innovative production technologies, cost-effective manufacturing techniques, close customer relations and support, and increasing product offerings. RESOURCE MATERIALS We use raw materials in the products we manufacture, including, among others, steel, aluminum, and polystyrene and other plastics resins. Steel is our most significant raw material input. We obtain nearly all of our steel inventory from large domestic suppliers. Managing price volatility and ensuring raw material availability are important aspects of our business. 17

Consistent with industry practice, our contracts with our metal fabrication customers incorporate steel cost pass-through mechanisms or indexed pricing that mitigates commodity volatility and its impact on profitability. Additionally, a certain amount of residual material (scrap) is a by-product of the manufacturing and production processes. We are able to sell nearly all scrap material in the scrap market. Declines in commodity prices for these scrap materials due to weakened demand or excess supply can negatively impact the profitability of our Manufacturing segment. SEASONALITY Demand for our products can be impacted by the seasonality of the demand for our customers' products and our customers' production schedules. Generally, sales volumes and earnings are lower in the fourth quarter. 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: 32% (2025), 35% (2024), 31% (2023) 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), founded in 1979 and acquired by Otter Tail Corporation in 1995, 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), founded in 1983 and acquired by Otter Tail Corporation in 2000, 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. OVERVIEW Our Plastics segment businesses manufacture PVC pipe primarily used in municipal water infrastructure, which encompasses potable water distribution, wastewater collection and distribution, and water reclamation systems. Potable water systems use PVC pressure pipe for transmission and distribution lines delivering treated water to residential and commercial developments. Wastewater and water reclamation systems use PVC pipe to transport non-potable water to treatment facilities or for reuse applications within municipal systems. Our Plastics segment businesses also manufacture PVC pipe for use within residential and commercial structures and rural water systems. The end markets and uses of our PVC pipe generally approximate the following: 90% Municipal; 5% Residential and Commercial; 5% Rural Water. PVC pipe is manufactured through an extrusion process, during which PVC resin 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, and up to 45 feet for certain types of pipe. All PVC pipe is manufactured to applicable standards and specifications defined by the American Water Works Association or ASTM International standards and are subject to rigorous internal quality assurances and third-party inspections for ongoing compliance. We have approximately 400 million pounds of annual nameplate production capacity between our facilities in Fargo, North Dakota and Phoenix, Arizona, with over 250,000 square feet of manufacturing and warehousing space. Our strategy is aimed at providing market-leading reliability and responsiveness, delivering quality products when our customers need them. Our agile operations provide us the flexibility to respond to customer needs and allow us to deliver the needed products in a timely manner. CUSTOMERS Substantially all of our products are sold through distributors, which range from large, national distributors to smaller regional or local distributors. In total, we sell to over 200 distribution customers, but do have a large volume of sales activity with two national distributors. In 2025, these two distributor customers combined to account for 47% of segment operating revenues. 18

Our distributor customers serve contractors, municipalities and other local governmental entities engaged in public infrastructure projects and residential and commercial development. Demand for our products is influenced by new construction development, as growth in residential and commercial building activity drives municipal water infrastructure, and system rehabilitation and replacement as aging municipal systems require upgrades or replacement. Our sales and service territory generally includes the western half of the U.S. and western Canada. We market our products through a combination of independent sales representatives, company salespeople and customer service representatives. The principal method for the distribution of our products is by common carrier ground transportation. COMPETITIVE CONDITIONS Competition in the PVC pipe industry is characterized by a limited number of domestic PVC pipe manufacturers, with the three largest competitors capturing a significant portion of the overall market. These large competitors have a broader geographical reach, integration with PVC resin producers, greater manufacturing capacity and national relationships with key distributors. Competition is generally geographically regionalized as shipping costs are typically cost prohibitive to compete on a national basis. The principal factors of competition are price, customer service, product availability, shipping costs and product performance. 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 products compete 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 and quality, including being a responsive and reliable partner to our customers through maintaining product availability, by producing high-quality products and by using cost-effective production techniques. RESOURCE MATERIALS There are four domestic manufacturers of PVC resin, the primary material input used in the manufacturing of PVC pipe. In 2025, we utilized all four vendors to source our PVC resin. We maintain contractual arrangements with certain PVC resin manufacturers. These multi-year agreements include estimated annual order quantities, with no required minimum purchases, and negotiated pricing based on the market price of resin. The supply of PVC resin may be limited at times due to insufficient manufacturing capacity or limited availability of feedstock products. Most U.S. resin production facilities are located in the Gulf Coast region. These facilities are subject to the risk of damage or production shutdowns because of exposure to hurricanes or other extreme weather events. We acquire PVC resin in bulk, shipped by rail to our facilities. We have the capability to store a limited supply of resin at our manufacturing plants. Due to the commodity nature of PVC resin and the dynamic supply and demand factors worldwide, the market for PVC resin can be 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. SEASONALITY Demand for our PVC pipe products can be impacted by seasonal weather differences, with generally lower sales volumes realized in the first and fourth quarters 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. 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. Unforeseen risks and uncertainties, or those that we currently consider immaterial, could also affect our business, operating results, financial condition and liquidity. 19

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. If we are unable to manage these risks and complete our capital investment projects on budget and in a timely manner, it could have negative impact on our financial condition, operating results and liquidity. 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 temperatures negatively impact demand for electricity which can 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 risks 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. 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 and severe convective storms, could have negative financial consequences, including limiting our ability to secure sufficient insurance coverage, or leading to increased insurance costs. While we carry liability insurance, given an extreme event, if we were found to be liable for damages caused by the event, 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. 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. As our businesses continue to be subject to additional and changing environmental, health and safety laws and regulations, we could incur additional costs complying with requirements that are promulgated in the future. New laws or regulations, or changes to 20

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. 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 threatened or actual claims, proceedings, or investigations, including the currently ongoing proceedings and investigations related to our Plastics segment businesses and OTC, 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 a resulting settlement, could involve damages, sanctions, consent decrees or orders requiring us to make substantial future payments, preventing us from offering certain products or services, requiring us to change our business practices in a manner materially adverse to our business, otherwise disrupting our business, diverting management resources, damaging our reputation or otherwise having a material effect on our operations. The outcomes of these matters are inherently unpredictable and subject to significant uncertainties. 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 the 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. 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 and certain physical damage or third-party injuries, we have cybersecurity insurance related to a breach event. However, damage and claims arising from such incidents may not be covered or may exceed the amount of any available insurance. The loss of, or significant reduction in revenue from, any of our key customers could have an adverse effect on our operating results. In 2025, no single customer provided more than 10% of our consolidated operating revenues, however, each of our segments had customers which accounted for over 10% of the segment’s operating revenues. In 2025, two customers combined to account for 16% of Electric segment revenues, three customers combined to account for 44% of Manufacturing segment operating revenues and two customers combined to account for 47% of Plastics segment operating revenues. The loss of any one of these customers or a significant decline in sales to these customers would have a significant negative impact on the segment's financial condition and operating results and could have a significant negative impact on the Company’s consolidated financial condition, operating results and liquidity. 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. We are subject to risks associated with our supply chain and trade regulations and tariffs. Our operations depend on the timely and cost-effective procurement and transportation of raw materials, including coal, natural gas, steel and aluminum, PVC resin and other materials. Global and domestic supply chain disruptions, which may be caused by numerous factors outside of our control, may affect the availability and pricing of critical materials and equipment. 21

Changes in trade policies, including tariffs and anti-dumping and countervailing duties, could increase the cost of certain materials used in constructing and maintaining our utility assets and impact the cost of raw materials used in our manufacturing processes. Specifically, tariffs arising from recent or ongoing anti-dumping and countervailing duty investigations could impact the cost of components necessary in constructing certain renewable generation assets. The imposition of such tariffs could increase the cost of our capital investments for which we are not guaranteed recovery. Alternatively, modifications to our material sourcing may delay our project plans and lead to increased costs. Recent federal legislation restricting the use of "foreign entities of concern" in the supply chain for energy-related projects may limit our ability to source certain components, particularly for renewable generation projects. Compliance with these requirements could result in higher project costs, longer lead times, the need to identify alternative suppliers and project delays. We face risks related to transportation logistics, including rail availability for coal and PVC resin, pipeline capacity and availability for natural gas and trucking capacity for steel and aluminum and other materials. Disruptions in these transportation systems, which can be caused by many factors outside of our control, could increase our costs or disrupt our operations. If we are unable to effectively manage our supply chain and trade-related risks, our operations could be adversely impacted, which may have a material impact on our operating results, financial position and liquidity. 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 strategic investment initiatives. 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, including interest rates, investment returns, future employee compensation levels, healthcare cost trends and mortality rates. Changes in any, or a combination, of these factors could have a significant effect on our funding obligations and the costs recognized for these plans. 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 cash provided by our subsidiary companies. Our ability to meet our financial obligations and pay dividends on our common stock principally depends on the earnings, cash flows, capital requirements and general financial position of our subsidiary companies. In addition, OTP is subject to federal and state regulations which may restrict its ability to pay dividends. Finally, we are also reliant on our subsidiary companies to maintain compliance with financial covenants under our various short- and long-term debt agreements. Our debt agreements include restrictions on the payment of cash dividends upon an event of default. Changes in tax laws, or failures to comply with tax credit eligibility requirements, 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 carry forward net operating losses and tax credits. Changes in tax laws, regulations and interpretations could have an adverse effect on our financial condition, operating results and liquidity. Tax law changes that reduce or eliminate production or investment tax credits (ITCs), or the ability to transfer or sell these credits, may impact the economics of constructing certain electric generation resources, which may impact our planned investments, and could adversely affect our financial condition and operating results. Failure to meet initial and ongoing tax credit eligibility requirements could also adversely impact our financial condition, operating results and liquidity. 22

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 earning 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, there is no assurance that we will be authorized to recover a rate of return on our investments that 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 case or other proceeding could adversely impact our financial condition, operating results and liquidity. 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. Recently, the NDPSC and North Dakota’s federal legislators have opposed cost recovery for projects in MISO Tranche 2.1, challenging renewable energy goals built into MISO’s benefits calculation for the projects. Federal and state opposition may impact our future capital investment opportunities; and may result in inefficiencies which could negatively impact our financial position, operating results and liquidity. Regulatory requirements to competitively bid capital projects could impact our ability to construct and own utility assets. A lack of direct ownership of such investments could impact our ability to achieve our strategic financial goals and adversely impact our operating results. 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 or federal 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, 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 latest 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 or 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 RHR as part of the state of North Dakota's RHR SIP. 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 23

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. New regulations recently finalized by the EPA require existing coal-fired power plants to achieve certain CO2 emissions reduction levels, with the level of reduction dependent upon the remaining operating life of the facility. At this time, we cannot determine how this may impact our power plants and the potential impact on 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. 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. 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. We attempt to mitigate the risk of regulatory penalties through our compliance program. However, there is no guarantee our program will be sufficient to prevent compliance 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 electric 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 (IT) systems. Further, the information systems that operate OTP’s electric system are interconnected to external networks. Parties that wish to disrupt the U.S. bulk power system or OTP’s operations could view OTP’s computer systems, software or networks as attractive targets for cyber attack. In addition, OTP’s generation and transmission facilities are spread throughout a large service territory. These facilities could be subject to physical attack or vandalism that could disrupt OTP’s operations or conceivably the regional or U.S. bulk power system. OTP is subject to mandatory cybersecurity and physical security regulatory requirements. OTP implements the NERC standards for operating its transmission and generation assets and remains abreast of best practices within the business and the utility industry to protect its computers and computer-controlled systems from outside attack. We rely on industry-accepted security measures and technology to securely maintain confidential and proprietary information necessary for the operation of our systems. In an effort to reduce the likelihood and severity of cyber intrusions, we have cybersecurity processes and controls, and disaster recovery plans designed to protect and preserve the confidentiality, integrity and availability of data and systems. We also take prudent and reasonable steps to protect the physical security of our 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 attacks on our generation or transmission facilities could adversely affect our business and our financial condition, operating results and liquidity. 24

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, and 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 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 or other factors, could lead to increased capacity prices. Significantly higher than expected energy or capacity costs could negatively affect our financial condition, operating results and liquidity. Our electric facilities are subject to operational risks, which could result in injuries, loss of life, property damage and liability claims. The operation of our generation, transmission and distribution facilities involves many risks including the potential for 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 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. 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 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. 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; 25

• 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; • seasonality of demand for our customers’ products, which may cause our manufacturing capacity to be underutilized for periods of time; and • product design changes or manufacturing process changes that may reduce or eliminate demand for the components we supply. We expect future sales will continue to depend on the success of our customers. If economic conditions or demand for our customers’ products deteriorates, we may experience a material adverse effect on our financial condition, operating results and liquidity. 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. 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, some of which have broader product lines, greater distribution capabilities, greater capital resources, greater marketing and research and development capabilities, or lower cost structures. 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 business 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 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, 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; and 26

• 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 peak 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. PVC resin is a commodity product. Its market price is impacted by global supply and demand conditions along with feedstock component pricing. Both of these factors can create volatile pricing for PVC resin, the primary material input used in manufacturing our PVC pipe products. Changes in the cost of PVC resin directly impact our profit margins. In addition, changes in PVC resin cost can impact the pricing of PVC pipe price. We may be unable to fully, or in a timely manner, adjust the pricing of PVC pipe in response to changing PVC resin costs. Accordingly, our operating results and liquidity could be materially impacted. 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 2025, 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 or 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 are 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. We face intense competition in the plastic pipe industry from other PVC pipe manufacturers. Certain 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 compete 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. 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 and vendor 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 IT 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 27

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 government 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 at least 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 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 IT managers, IT security subject matter experts, and internal audit personnel and is led by our Vice President of Information Security and Technology who has more than 20 years of experience in IT, enterprise security and cyber risk management, and holds a Certified Information Systems Security Professional designation. 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 as 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, operational, 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 review our mitigation strategies. 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 Information Security and Technology 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, the Board of Directors reviews the results of our penetration and vulnerability testing annually. 28

ITEM 2. PROPERTIES The following provides a summary of our properties which are material to our operations, by segment, as of December 31, 2025. ELECTRIC SEGMENT The following reflects our wholly or jointly owned material electric generation facilities as of December 31, 2025: Description Location Year Placed in Service Fuel Type Capacity - kW (Nameplate Rating) Big Stone Plant(1) Big Stone City, SD 1975 Subbituminous Coal 256,025 Coyote Station(2) Beulah, ND 1981 Lignite Coal 149,450 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, 2025 as follows: Miles Transmission 345 kV(1) 891 230 kV(2) 494 115 kV 975 Less than 115 kV 3,990 Distribution Less than 115 kV 8,024 (1) As of December 31, 2025, OTP held a 14.2% ownership interest of 242 miles, a 4.8% ownership interest of 250 miles, and a 50.0% ownership interest of 234 miles of the 345 kV transmission lines, with the remaining miles being wholly owned. (2) As of December 31, 2025, OTP held a 14.8% ownership interest of 70 miles of the 230 kV transmission lines, with the remaining miles being wholly owned. 29

MANUFACTURING AND PLASTICS SEGMENTS The following reflects the properties of our Manufacturing and Plastic segments as of December 31, 2025 which are significant to our operations: Segment/Location Owned/Leased Facility Type/Use Approximate Square Feet Manufacturing Segment St. Cloud, MN Leased Warehouse 60,000 Otsego, MN Leased Manufacturing/Warehouse 86,000 Clearwater, MN Owned Office/Manufacturing/Warehouse 204,000 Washington, IL Leased Office/Manufacturing/Warehouse 218,000 Dawsonville, GA Owned Office/Manufacturing/Warehouse 335,000 Detroit Lakes, MN Owned Office/Manufacturing/Warehouse 360,000 Lakeville, MN Leased Office/Manufacturing/Warehouse 443,000 Plastics Segment Fargo, ND Owned Office/Manufacturing/Warehouse 122,000 Phoenix, AZ Owned Office/Manufacturing/Warehouse 144,000 We believe the facilities described above are adequate for our present business. ITEM 3. LEGAL PROCEEDINGS Several class action complaints have been filed against Northern Pipe Products, Vinyltech Corporation, Otter Tail Corporation and over 20 other parties. The complaints allege, among other things, that our companies and the other defendants and alleged co- conspirators conspired to fix, raise, maintain, and stabilize the price of PVC municipal water, PVC plumbing pipe, PVC pipe fixtures and PVC conduit pipe in violation of United States federal and state antitrust laws, Canadian competition laws, and consumer protection and competition 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 (61) 04/13/15 President and Chief Executive Officer Todd R. Wahlund (55) 01/01/24 Vice President, Chief Financial Officer Timothy J. Rogelstad (59) 04/14/14 Senior Vice President, Electric Platform John S. Abbott (67) 02/11/15 Senior Vice President, Manufacturing Platform Jennifer O. Smestad (55) 01/01/18 Senior 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 Vice President, Chief Financial Officer 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 Senior Vice President, General Counsel and Corporate Secretary since April 13, 2025, and previously served as Vice President, General Counsel and Corporate Secretary of the Company from January 1, 2018 to April 12, 2025. 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. 30

ITEM 4. MINE SAFETY DISCLOSURES Not Applicable. 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, 2025, there were 9,748 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, 2025. PERFORMANCE GRAPH COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN This graph compares the cumulative total shareholder return (TSR) 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, 2020, and reinvestment of all dividends). OTTR EEI Nasdaq 2020 2021 2022 2023 2024 2025 $100 $150 $200 2020 2021 2022 2023 2024 2025 OTTR $ 100.00 $ 170.99 $ 145.77 $ 215.82 $ 193.56 $ 219.89 EEI $ 100.00 $ 117.12 $ 118.47 $ 108.16 $ 128.82 $ 143.83 Nasdaq $ 100.00 $ 125.89 $ 101.05 $ 127.76 $ 159.03 $ 186.96 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 31

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. 2025 FINANCIAL RESULTS In 2025, our diversified business model generated strong financial results, producing net income of $275.9 million, or $6.55 per diluted share. As expected, our earnings declined from the record level achieved in 2024 when we generated earnings of $301.7 million, or $7.17 per diluted share. As we anticipated, product prices within our Plastics segment continued to decline in 2025 leading to the reduction in earnings compared to the prior year. We anticipate earnings from our Plastics segment will continue to decline through 2027 until such time that product pricing is expected to stabilize. We generated $386.0 million of cash from operations in 2025 and ended the year with total available liquidity of $705.5 million. Our year-end equity ratio to total capital was 62.8%. We paid dividends totaling $2.10 per share, or $88.1 million, marking our 87th consecutive year of dividend payments to our shareholders. Our Electric segment generated 7% earnings growth in 2025, producing earnings of $97.6 million. Our earnings growth was driven by the recovery of our rate base investments, which include investments in new generation and enhancements to our transmission and distribution system to promote reliable electric service. We also benefited from increased sales volumes in 2025, partially the result of favorable weather conditions compared to last year which impacted our customers' demand for energy, and lower operating and maintenance costs. Earnings in our Manufacturing segment decreased 16% in 2025 to $11.5 million. Our sales volumes in the year were negatively impacted by soft end-market demand and customer inventory management efforts within many of the end markets we serve. Weak farm economics, persistently elevated interest rates, a cautious consumer and tariff uncertainty led to demand headwinds. We were able to partially mitigate the financial effects of lower sales volumes through cost-management efforts aligning our cost structure with the current demand environment, and enhanced production efficiencies. Our Plastics segment earnings decreased 15% in 2025 to $170.4 million. As anticipated, sales prices for our PVC pipe products, after peaking in 2022, have gradually declined, including in 2025 when average prices declined 15% compared to the prior year. This pricing decline was the primary driver of our lower earnings in 2025. Partially offsetting the decline in product pricing was reduced material input costs and higher sales volumes. Our sales volumes in 2025 benefited from the additional production capacity and large diameter pipe capability installed at our Phoenix location in late 2024. In 2025, our earnings mix was 35% from our Electric segment and 65% from the combination of our Manufacturing and Plastics segments including unallocated corporate costs. Since 2021, this mix has diverged from our long-term target of 70% Electric and 30% Manufacturing Platform, largely due to market conditions in the PVC pipe industry. These conditions have resulted in elevated revenue, earnings, and cash flow in our Plastics segment. We currently expect industry conditions within the PVC pipe market to gradually normalize through 2027. As this normalization occurs, we anticipate that earnings and cash flow from our Plastics segment will moderate from current levels and that our earnings mix will shift back toward our long-term target. FINANCIAL AND OTHER METRICS Heating Degree Days (HDDs) is a measure of how much (in degrees), and for how long (in days), the outside air temperature was below a certain normalized level. Normal weather conditions are defined as the 20-year average of actual historical weather conditions. This measure is commonly used in calculations relating to the energy consumption required to heat buildings. Cooling Degree Days (CDDs) is a measure of how much (in degrees), and for how long (in days), the outside air temperature was above a certain normalized level. This measure is commonly used in calculations relating to the energy consumption required to cool buildings. OTP generally bases its forecasted kwh sales and rates on expected consumption under a normal level of HDDs and CDDs over a given period of time in its service territory. 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 2024 to 2023, 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, 2024, filed with the SEC on February 19, 2025. 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 32

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, 2025 and 2024: (in thousands) 2025 2024 $ change % change Operating Revenues $ 1,304,058 $ 1,330,548 $ (26,490) (2.0) % Operating Expenses 958,376 950,298 8,078 0.9 Operating Income 345,682 380,250 (34,568) (9.1) Interest Expense (47,226) (41,815) (5,411) 12.9 Nonservice Components of Postretirement Benefits 3,334 9,609 (6,275) (65.3) Other Income 20,487 18,848 1,639 8.7 Income Before Income Taxes 322,277 366,892 (44,615) (12.2) Income Tax Expense 46,384 65,230 (18,846) (28.9) Net Income $ 275,893 $ 301,662 $ (25,769) (8.5) % Operating Revenues decreased $26.5 million in 2025 primarily due to decreased sales prices in our Plastics segment and decreased sales volumes in our Manufacturing segment, partially offset by increased sales volumes in our Plastics segment as well as increased fuel recovery revenues and sales volumes in our Electric segment. See our segment disclosures below for additional discussion of items impacting operating revenues. Operating Expenses increased $8.1 million in 2025 primarily due to an increase in purchased power costs, production fuel costs, and depreciation expense in our Electric segment, partially offset by lower cost of goods sold driven by decreased sales volumes in our Manufacturing segment and the impact of lower material costs in our Plastics segment, as well as lower operating and maintenance expenses in our Electric segment. See our segment disclosures below for additional discussion of items impacting operating expenses. Interest Expense increased $5.4 million in 2025 primarily due to the issuance of $100.0 million of long-term debt at OTP during the year, the proceeds of which were used to repay short-term borrowings, fund capital expenditures and support operating activities. Nonservice Components of Postretirement Benefits decreased by $6.3 million in 2025, having a negative impact on net income, primarily due to a decrease in the amortization of postretirement plan amendment-related gains and an increase in the amortization of actuarial losses. Income Tax Expense decreased $18.8 million in 2025 primarily due to a decrease in income before income taxes, as well as an increase in PTCs at OTP. The increase in PTCs was the result of increased wind generation that qualified for tax credits. We completed the first of our wind facility upgrades in late 2024 and completed additional upgrades throughout 2025. The completion of these upgrades resulted in the commencement of PTCs earned from the generation at these facilities. Our effective tax rate was 14.4% in 2025 and 17.8% in 2024, with the decrease primarily driven by the increase in PTCs. 33

ELECTRIC SEGMENT RESULTS The following table summarizes the operating results of our Electric segment for the years ended December 31, 2025 and 2024: (in thousands) 2025 2024 $ change % change Retail Revenue $ 484,016 $ 453,214 $ 30,802 6.8 % Transmission Services Revenue 54,656 53,517 1,139 2.1 Wholesale Revenue 21,121 11,077 10,044 90.7 Other Electric Revenues 6,963 6,707 256 3.8 Total Operating Revenue 566,756 524,515 42,241 8.1 Production Fuel 75,048 60,945 14,103 23.1 Purchased Power 78,658 61,561 17,097 27.8 Operating and Maintenance Expenses 184,310 190,422 (6,112) (3.2) Depreciation and Amortization 90,168 82,136 8,032 9.8 Property Taxes 17,023 15,662 1,361 8.7 Operating Income 121,549 113,789 7,760 6.8 Interest Expense (43,633) (38,216) (5,417) 14.2 Nonservice Cost Components of Postretirement Benefits 4,425 10,578 (6,153) (58.2) Other Income 3,446 3,268 178 5.4 Income Before Income Taxes 85,787 89,419 (3,632) (4.1) Income Tax Benefit (11,799) (1,544) (10,255) 664.2 Net Income $ 97,586 $ 90,963 $ 6,623 7.3 % Electric kwh Sales (in thousands) 2025 2024 kwh change % change Retail kwh Sales 5,917,736 5,681,268 236,468 4.2 % Wholesale kwh Sales 404,750 273,365 131,385 48.1 Heating Degree Days 6,117 5,313 804 15.1 Cooling Degree Days 492 440 52 11.8 % 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, 2025 and 2024: 2025 2024 Heating Degree Days 97.1 % 83.7 % Cooling Degree Days 102.5 % 93.8 % 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, 2025 and 2024, and between years: 2025 vs Normal 2025 vs 2024 2024 vs Normal Effect on Diluted Earnings Per Share $ (0.03) $ 0.10 $ (0.13) Retail Revenue increased $30.8 million primarily due to the following: • A $21.7 million increase in fuel recovery revenues due to higher purchased power and fuel costs, as described below. • An $8.7 million increase primarily from recovery of rate base investments. • A $6.1 million increase in sales volumes, exclusive of the impact of weather, primarily driven by increased customer usage. • A $5.7 million increase from the impact of favorable weather compared to last year. These increases were partially offset by a net decrease in rider revenues resulting from higher PTCs during the year following the completion of certain of our wind facility upgrades. PTCs generated during the year increased $9.6 million. These credits are generally passed through to customers, reducing retail revenue. 34

Wholesale Revenues increased $10.0 million due to a 29% increase in wholesale prices driven by increased fuel costs and market demand for wholesale energy, as well as a 48% increase in wholesale sales volumes. Wholesale revenues, net of wholesale fuel costs, are generally returned to customers and result in a reduction of retail revenue. Production Fuel costs increased $14.1 million driven by higher fuel consumption associated with increased generation at Big Stone Plant and our natural gas facilities in response to increased customer demand. Higher natural gas prices also contributed to the increase in production fuel costs. Purchased Power costs to serve retail customers increased $17.1 million due to a 20% increase in the price of purchased power, primarily due to increased market energy costs, as well as a 7% increase in the volume of purchased power driven by increased customer demand. Operating and Maintenance Expenses decreased $6.1 million primarily due to decreased labor costs. Compared to the last year, a greater percentage of labor hours were dedicated to capital investment projects, which resulted in an increase in capitalized labor costs and a corresponding reduction in operating and maintenance expenses. External service provider costs also decreased compared to last year. These decreases were partially offset by expenses related to a planned outage at Coyote Station during the year. Depreciation and Amortization expense increased $8.0 million due to additional assets, including certain wind generation, transmission and distribution assets, being placed into service during the year. Interest Expense increased $5.4 million primarily due to the issuance of an additional $100.0 million of long-term debt during the year, the proceeds of which were primarily used to repay short-term debt and fund our capital investments. Nonservice Cost Components of Postretirement Benefits decreased by $6.2 million, having a negative impact on net income, due to a decrease in the amortization of plan amendment-related gains and an increase in the amortization of actuarial losses. Income Tax Benefit increased $10.3 million primarily due to an increase in PTCs driven by increased wind generation that qualified for tax credits compared to last year. PTCs are generally credited to customers and result in a reduction of operating revenue as well as income taxes. MANUFACTURING SEGMENT RESULTS The following table summarizes the operating results of our Manufacturing segment for the years ended December 31, 2025 and 2024: (in thousands) 2025 2024 $ change % change Operating Revenues $ 314,547 $ 342,592 $ (28,045) (8.2) % Cost of Products Sold (excluding depreciation) 238,790 267,904 (29,114) (10.9) Selling, General, and Administrative Expenses 37,575 35,203 2,372 6.7 Depreciation and Amortization 21,282 20,393 889 4.4 Operating Income 16,900 19,092 (2,192) (11.5) Interest Expense (2,506) (2,516) 10 (0.4) Income Before Income Taxes 14,394 16,576 (2,182) (13.2) Income Tax Expense 2,877 2,895 (18) (0.6) Net Income $ 11,517 $ 13,681 $ (2,164) (15.8) % Operating Revenues decreased $28.0 million primarily driven by a 7% decline in sales volumes at our metal fabrication business, with reductions across several end markets, including agriculture, lawn and garden and recreational vehicles. Sales volumes were negatively affected by soft end-market demand and inventory management efforts by manufacturers and dealers throughout much of the year, continuing a trend that began in the third quarter of 2024. A 1% decrease in steel costs, which are passed through to customers, also contributed to the decrease in operating revenues. Cost of Products Sold decreased $29.1 million primarily due to lower sales volumes. Our gross profit margin increased to 24.1% in 2025 from 21.8% in the prior year. This improvement was driven by cost management efforts made to align our cost structure with the current demand environment, and improved labor productivity and production efficiencies. Selling, General, and Administrative Expenses increased $2.4 million primarily due to variable compensation costs. Depreciation and Amortization expense increased $0.9 million, largely driven by our facility expansion and new equipment at our BTD location in Georgia, which were placed into service in early 2025. 35

PLASTICS SEGMENT RESULTS The following table summarizes the operating results for our Plastics segment for the years ended December 31, 2025 and 2024: (in thousands) 2025 2024 $ change % change Operating Revenues $ 422,755 $ 463,441 $ (40,686) (8.8) % Cost of Products Sold (excluding depreciation) 163,874 166,628 (2,754) (1.7) Selling, General, and Administrative Expenses 21,380 20,414 966 4.7 Depreciation and Amortization 6,422 4,494 1,928 42.9 Operating Income 231,079 271,905 (40,826) (15.0) Interest Expense (685) (590) (95) 16.1 Other Income 5 76 (71) (93.4) Income Before Income Taxes 230,399 271,391 (40,992) (15.1) Income Tax Expense 59,999 70,644 (10,645) (15.1) Net Income $ 170,400 $ 200,747 $ (30,347) (15.1) % Operating Revenues decreased $40.7 million primarily driven by a 15% decline in sales prices compared to last year. Prices have been declining for several years after peaking in late 2022. The impact of lower sales prices was partially offset by an 8% increase in sales volumes, largely driven by additional production capacity following the completion of the first phase of our expansion project at Vinyltech in late 2024. Cost of Products Sold decreased $2.8 million primarily reflecting a 14% reduction in the cost of input materials, including PVC resin. The reduction in PVC resin cost was driven by global supply and demand dynamics which has resulted in elevated resin supply. This decrease was partially offset by higher sales volumes, as discussed above. Selling, General, and Administrative Expenses increased $1.0 million primarily due to costs associated with ongoing litigation and related matters regarding the pricing of PVC pipe, which is further described in Note 14 to the consolidated financial statements. There is considerable uncertainty regarding the timing of significant developments or the resolution of these matters. As such, it is reasonably possible that our estimate of a loss, if any, arising from these matters could change in the near term and have a material impact on our future operating results. Depreciation and Amortization expense increased $1.9, largely driven by our facility expansion and new equipment at Vinyltech, which were placed into service in late 2024. Income Tax Expense decreased $10.6 million due to a decrease in income before taxes. CORPORATE The following table summarizes Corporate results of operations for the years ended December 31, 2025 and 2024: (in thousands) 2025 2024 $ change % change Selling, General, and Administrative Expenses $ 23,611 $ 24,438 $ (827) (3.4) % Depreciation and Amortization 235 98 137 139.8 Operating Loss 23,846 24,536 (690) (2.8) Interest Expense (402) (493) 91 (18.5) Nonservice Cost Components of Postretirement Benefits (1,091) (969) (122) 12.6 Other Income 17,036 15,504 1,532 9.9 Loss Before Income Taxes 8,303 10,494 (2,191) (20.9) Income Tax Benefit (4,693) (6,765) 2,072 (30.6) Net Loss $ 3,610 $ 3,729 $ (119) 3.2 % Other Income increased $1.5 million driven by higher investment income earned on our short-term investments resulting from increased cash available for investment, as well as gains on our corporate-owned life insurance policies. Income Tax Benefit decreased $2.1 million primarily due to a decrease in loss before taxes. 36

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 recently concluded 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) 03/15/25 225.6 7.53 10.10 53.50 South Dakota(2) 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) 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%. South Dakota Rate Case On June 4, 2025, OTP filed a request with the South Dakota Public Utilities Commission (SDPUC) for an increase in revenue recoverable under general rates in South Dakota. In its filing, OTP requested a net increase in annual revenue of $5.7 million, or 12.50%, based on an allowed rate of return on rate base of 8.29% and an allowed ROE of 10.80% on an equity ratio of 53.54% of total capital. Through this proceeding, OTP has proposed changes to the mechanism of certain cost and investment recovery, with recovery moving from riders into base rates. Interim rates went into effect on December 1, 2025, and are subject to potential refund until the finalization of the rate case. Minnesota Rate Case On October 31, 2025, OTP filed a request with the MPUC for an increase in revenue recoverable under general rates in Minnesota. In its filing, OTP requested a net increase in annual revenue of $44.8 million, or 17.7%, based on an allowed rate of return on rate base of 7.92% and an allowed ROE of 10.65% on an equity ratio of 53.5% of total capital. The request includes, among other items, accelerated recovery of the remaining investment of the jurisdictionally allocated share of Coyote Station, which has a $4.3 million annual impact. The request for accelerated recovery is driven by the MPUC’s order in OTP’s most recent IRP to discontinue serving Minnesota customers with capacity and energy from Coyote Station prior to the currently estimated end of its useful life. If this part of the request is granted, we anticipate the amounts collected would be deferred and recognized over the remaining estimated useful life of the plant, which extends until 2041. The filing also included an interim rate request for a net increase in annual revenue of $31.8 million, or 12.6%. On December 23, 2025, the MPUC approved the interim rate request with a modification to exclude the impact of the accelerated recovery of the remaining investment of the jurisdictionally allocated share of Coyote Station from interim rates. The resulting interim net increase in annual revenue is $28.6 million, or 11.3%. Interim rates went into effect on January 1, 2026, and are subject to potential refund until the finalization of the rate case. 37

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 ECO - 2025 MN Approved 04/01/25 9.5 12/01/25 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. TCR - 2026 ND Approved 09/15/25 5.1 02/01/26 Recovery of transmission project costs. TCR - 2024 ND Approved 11/02/23 4.5 01/01/24 Recovery of transmission project costs. MDT - 2026 ND Approved 08/01/25 3.7 01/01/26 Recovery of advanced metering infrastructure and demand-response projects. TCR - 2025 ND Approved 09/16/24 3.1 01/01/25 Recovery of transmission project costs. PIR - 2025 SD Approved 12/20/24 3.2 09/01/25 Recovery of Ashtabula III, Merricourt, Astoria Station, Abercrombie Solar, Solway Solar, wind upgrade projects, advanced metering infrastructure, outage management system, demand-response system, and impact of load- growth credits. 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. OTHER In July 2025, the utility commissions from five states, including the NDPSC, filed a complaint with FERC challenging MISO’s analysis supporting the benefits of MISO’s Tranche 2.1 portfolio of transmission projects. The complaint alleges that the benefits of the Tranche 2.1 projects do not exceed forecasted costs and contends that MISO lacks the authority to direct these projects under the current cost allocation system. FERC has not established a timeline to review this matter and no statutory deadline exists. OTP will be a co-owner of three projects within the Tranche 2.1 portfolio of projects, with an estimated total capital investment of approximately $800 million to $1.0 billion. The complaint, FERC’s adjudication of it, and potential rehearing proceedings and legal challenges to the outcome, could delay OTP’s investments or result in the cancellation of the projects. 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 our 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, 2025, we were in compliance with all financial covenants (see the Financial Covenant section under Capital Resources below). 38

The following table presents the status of our lines of credit as of December 31, 2025: 2025 (in thousands) Line Limit Amount Outstanding Letters of Credit Amount Available OTC Credit Agreement $ 170,000 $ — $ — $ 170,000 OTP Credit Agreement 220,000 60,242 10,461 149,297 Total $ 390,000 $ 60,242 $ 10,461 $ 319,297 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, 2025, we had $319.3 million of available liquidity under our credit agreements and $386.2 million of available cash and cash equivalents, resulting in total available liquidity of $705.5 million, compared to total available liquidity of $606.3 million as of December 31, 2024. CASH FLOWS The following is a discussion of our cash flows for the years ended December 31, 2025 and 2024: (in thousands) 2025 2024 Net Cash Provided by Operating Activities $ 385,985 $ 452,731 Net Cash Provided by Operating Activities decreased $66.7 million primarily due to higher working capital requirements, largely in our Electric segment, and a decrease in earnings. These working capital changes were largely driven by the timing of capital spending and the timing of fuel cost and rider recoveries from our utility customers. Operating cash flows in our Electric segment may fluctuate materially from period to period because they are significantly influenced by the timing of payments for operating costs and the regulatory mechanisms through which we recover or return costs. The timing of these recoveries and refunds varies depending on the specific cost-recovery mechanism approved by regulators. As a result, cash provided by operating activities may differ significantly from net income in any given reporting period. Market dynamics experienced by our Plastics segment businesses in 2025 and 2024 contributed to a substantial increase in consolidated cash from operations over this period. We expect cash provided by operating activities in future years to decline from recent levels, consistent with the anticipated normalization of earnings in the Plastics segment. (in thousands) 2025 2024 Net Cash Used in Investing Activities $ 290,724 $ 411,374 Net Cash Used in Investment Activities decreased $120.7 million, primarily the result of a $70.6 million decrease in capital expenditures. Capital expenditures in our Manufacturing and Plastics segments decreased $40.1 million following the completion of our expansion projects at Vinyltech and BTD Manufacturing in late 2024 and early 2025. Capital expenditures in our Electric segment also decreased, primarily due to the timing of investments under our capital spending plan. Investing activities in 2024 also included a $50.1 million investment in U.S. treasuries, which was made to secure a fixed rate of return until their maturity in September 2026. (in thousands) 2025 2024 Net Cash Provided by (Used in) Financing Activities $ (3,719) $ 22,921 Net Cash Used in Financing Activities totaled $3.7 million in 2025, compared with $22.9 million of net cash provided by financing activities in 2024. Financing activities in 2025 included the issuance of $100.0 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. In 2024, financing activities included the issuance of $120.0 million of long-term debt at OTP. We manage OTP's capital structure independently from our consolidated financial position to ensure compliance with the capital structure approved 39

through regulation. As a result, decisions related to the issuance of long-term debt at OTP are not influenced by our consolidated cash and cash equivalent position. Financing activities during 2025 also included net repayments of short-term debt of $9.4 million, compared with net repayments of $11.8 million in 2024. Dividend payments totaled $88.1 million in 2025, compared to $78.3 million in 2024. 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, 2025 and 2024 for our Electric segment and non-electric businesses and anticipated capital expenditures for the five-year period from 2026 through 2030: (in millions) 2024 2025 2026 2027 2028 2029 2030 Total 2026 - 2030 Electric Segment: Renewable Generation and Storage $ 134 $ 91 $ 251 $ 295 $ 89 $ 4 $ 6 $ 645 Transmission 60 50 80 167 167 186 255 855 Distribution 46 88 55 49 53 54 57 268 Other 61 42 50 36 24 23 20 153 Total Electric Segment 301 271 436 547 333 267 338 1,921 Manufacturing and Plastics Segments 58 17 31 27 29 23 19 129 Total Capital Expenditures $ 359 $ 288 $ 467 $ 574 $ 362 $ 290 $ 357 $ 2,050 CONTRACTUAL AND OTHER OBLIGATIONS The following table summarizes our contractual obligations on December 31, 2025 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 $ 1,107 $ 140 $ 42 $ 120 $ 805 Interest on Debt Obligations 773 47 87 79 560 Coal Contract Obligations 417 24 51 53 289 Equipment Purchase Obligations 53 12 41 — — Land Easement Payments 56 2 4 4 46 Postretirement Benefit Obligations 70 6 12 12 40 Operating Lease Obligations 34 7 10 6 11 Other Obligations 23 4 8 5 6 Total Contractual Obligations $ 2,533 $ 242 $ 255 $ 279 $ 1,757 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. COMMON STOCK DIVIDENDS We paid dividends to our shareholders totaling $88.1 million, or $2.10 per share, in 2025. 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 40

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 January 8, 2026, our Board of Directors approved a quarterly dividend of $0.5775 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 2026 through 2030 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. 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, 2025, there were 1,330,821 shares available for purchase or issuance under the plan. Both registration statements expire in May 2027. SHORT-TERM DEBT The OTC Credit Agreement and OTP Credit Agreement provide for unsecured revolving lines of credit. Outstanding balances under these facilities bear interest at a variable rate comprised of a benchmark rate 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, 2025 and 2024 was 5.08% and 5.61%. The following is a summary of key provisions and borrowing information as of and for the year ended December 31, 2025: (in thousands, except interest rates) OTC Credit Agreement OTP Credit Agreement Borrowing Limit $ 170,000 $ 220,000 Borrowing Limit if Accordion Exercised1 290,000 300,000 Amount Restricted Due to Outstanding Letters of Credit at Year-End — 10,461 Amount Outstanding at Year-End — 60,242 Average Amount Outstanding During Year — 34,479 Maximum Amount Outstanding During the Year — 111,820 Interest Rate at Year-End 5.19 % 5.08 % Expiration Date December 11, 2030 December 11, 2030 1Each facility includes an accordion feature allowing the borrower to increase the borrowing limit if certain terms and conditions are met. LONG-TERM DEBT In March 2025, OTP entered into a Note Purchase Agreement pursuant to which OTP issued, in a private placement transaction, $100.0 million of senior unsecured notes consisting of (a) $50.0 million of 5.49% Series 2025A Senior Unsecured Notes due March 27, 2035, and (b) $50.0 million of 5.98% Series 2025B Senior Unsecured Notes due June 5, 2055. 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, 2025, we had $1.0 billion 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 2055. 41

Financial Covenants Our short- and long-term debt agreements require OTC and OTP to maintain certain financial covenants. As of December 31, 2025, 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, 2025, OTC's interest-bearing debt to total capitalization was 0.38 to 1.00, OTC's interest and dividend coverage ratio was 8.02 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, 2025, OTP's interest-bearing debt to total capitalization was 0.47 to 1.00, OTP's interest and dividend coverage ratio was 2.97 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 Baa1 BBB+ BBB+ Senior Unsecured Debt n/a BBB n/a n/a A- n/a Outlook Stable Stable Positive Stable Stable Stable 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 require 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 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 current 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 42

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, 2025 and 2024, we had regulatory assets of $106.5 million and $108.6 million and regulatory liabilities of $314.0 million and $318.2 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 actuarially determined and incorporate numerous assumptions, including a discount rate, an expected return on plan assets, compensation changes, healthcare cost-trend rates and other demographic assumptions. These assumptions are reviewed annually, or more frequently under certain circumstances. Discount Rate - the discount rate used to measure pension and other postretirement benefit obligations should reflect the rate at which the obligations could be effectively settled as of the measurement date. We estimate the discount rate using 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. Lower discount rates increase the benefit obligation and future pension expense, while higher discount rates reduce such amounts. Expected Return on Plan Assets - we estimate the long-term expected rate of return on pension plan assets based on asset category studies using historical returns and forward-looking capital market assumptions based on our asset allocation. Differences between expected and actual returns are recognized as actuarial gains or losses and amortized to expense over time. Other Assumptions - additional assumptions applicable to the measurement of benefit obligations and expense for some or all of our plans include projected participant compensation changes, healthcare cost trends, mortality or life expectancy, and other demographic assumptions. We estimate these items by reference to relevant third-party information, internal projections and historical experience of our plan participants. Differences between our assumptions and actual results are recognized as actuarial gains or losses and amortized to expense over time. Actuarial gains and losses reflect differences between actual plan experience and our actuarial assumptions, as discussed above. Such actuarial gains and losses can materially impact our benefit obligations, in certain instances plan funding requirements, and plan expense. Actuarial gains and losses are initially recognized as a component of accumulated other comprehensive income or as a regulatory asset or liability and are subsequently amortized to plan expense. We have elected to apply a corridor approach as allowed under applicable accounting standards to determine the amount of actuarial gains and losses amortized to plan expense. This approach is intended to moderate short-term fluctuations in pension expense. Under the corridor method, actuarial gains and losses are amortized to plan expense only when they exceed 10% of the greater of the benefit obligation or, where applicable, the market value of plan assets for our funded pension plan. Cumulative gains and losses in excess of the 10% threshold are amortized to plan expense generally over the expected average remaining future service period of active plan participants, which for our pension plan is currently approximately 10 years. 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 following table summarizes the discount rates used to measure our pension plan and other postretirement obligations, as well as the assumed rate of return on pension plan assets for our funded pension plan, as of December 31, 2025 and 2024: 2025 2024 change Pension Plan (Pension): Discount Rate 5.71 % 5.70 % 1 bp Long-Term Return on Plan Assets 7.00 % 7.00 % — Pension Plan (ESSRP): Discount Rate 5.46 % 5.60 % (14 bps) Other Postretirement Benefits: Discount Rate 5.47 % 5.61 % (14 bps) 43

The following table summarizes the impact on 2025 pension and postretirement costs of a 25-basis point increase or decrease, holding all other variables constant, on certain key assumptions: (in thousands) +0.25 -0.25 Discount Rate $ (807) $ 840 Rate of Increase in Future Compensation1 515 (497) Long-Term Return on Plan Assets2 (884) 884 1 Not applicable to the postretirement healthcare plan. 2 Not applicable to the ESSRP or postretirement healthcare plan. For 2026, we expect pension and other postretirement benefit income to be $0.5 million compared to $2.4 million in 2025 due to the impacts of updated actuarial assumptions. Pension and postretirement benefit liabilities and plan expense are sensitive to changes in actuarial assumptions and differences between these assumptions and actual plan experience. Our financial position and operating results could be materially impacted by these factors. We believe the estimates made for our pension and other postretirement benefit plans are reasonable and based on the best information available. 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, 2025, BTD Manufacturing and our Plastics segment carried goodwill balances of $18.1 million and $19.3 million, respectively. 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 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 2025 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 the 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. 44

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 rate-making 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, 2025, OTP was party to financial swap agreements with an aggregate notional amount of 310,600 megawatt-hours of electricity with various settlement dates throughout 2026. As of December 31, 2025, the aggregate fair value of these instruments was a net $2.6 million liability. Holding other variables constant, a ten percent change in energy prices would have had an approximate $1.5 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 segments 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 the secured overnight financing rate (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, 2025 and 2024, we had $60.2 million and $69.6 million of short-term debt outstanding. Holding other variables constant, a 100-basis point change in interest rates during 2025 would have had an approximate $0.3 million impact to interest expense in 2025 based on our average outstanding short-term debt during the year. As of December 31, 2025 and 2024, we had $372.4 million and $282.0 million invested in cash equivalent investments. Holding other variables constant, a 100-basis point change in the average interest rates during 2025 would have had an approximate $2.8 million impact on our investment income in 2025, based on our average investment balance during the year. All of our outstanding long-term debt obligations as of December 31, 2025 and 2024 had fixed interest rates and were not subject to material interest rate risk. We manage our interest rate risk through the issuance of fixed-rate debt with varying maturities, by limiting the amount of variable interest rate debt and the utilization of short-term borrowings to allow flexibility in the timing and placement of long-term debt. We have not used hedging instruments to manage interest risk arising from our portfolio of borrowings. We maintain a ratio of fixed-rate debt to total debt within a certain range. It is our policy to enter into interest rate transactions and other financial instruments only to the extent considered necessary to meet our stated objectives. We do not enter into interest rate transactions for speculative or trading purposes. 45

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, 2025 and 2024, 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, 2025, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the "financial statements"). We also have audited the Company's internal control over financial reporting as of December 31, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, 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, 2025, 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 46

/s/ Deloitte & Touche LLP Minneapolis, Minnesota February 18, 2026 We have served as the Company's auditor since 1944.

OTTER TAIL CORPORATION CONSOLIDATED BALANCE SHEETS December 31, (in thousands, except share data) 2025 2024 Assets Current Assets Cash and Cash Equivalents $ 386,193 $ 294,651 Receivables, net of allowance for credit losses 145,496 145,964 Inventories 158,598 148,885 Investments 54,311 753 Regulatory Assets 20,437 9,962 Other Current Assets 34,690 29,826 Total Current Assets 799,725 630,041 Noncurrent Assets Investments 78,823 121,177 Property, Plant and Equipment, net of accumulated depreciation 2,876,685 2,692,460 Regulatory Assets 86,062 98,673 Intangible Assets, net of accumulated amortization 4,642 5,743 Goodwill 37,572 37,572 Other Noncurrent Assets 80,770 66,416 Total Noncurrent Assets 3,164,554 3,022,041 Total Assets $ 3,964,279 $ 3,652,082 Liabilities and Shareholders' Equity Current Liabilities Short-Term Debt $ 60,242 $ 69,615 Current Maturities of Long-Term Debt 79,951 — Accounts Payable 93,606 113,574 Accrued Salaries and Wages 35,666 34,398 Accrued Taxes 18,460 17,314 Regulatory Liabilities 16,600 29,307 Other Current Liabilities 46,433 45,582 Total Current Liabilities 350,958 309,790 Noncurrent Liabilities and Deferred Credits Pension Benefit Liability 32,376 32,614 Other Postretirement Benefits Liability 31,813 27,385 Regulatory Liabilities 297,398 288,928 Deferred Income Taxes 305,931 267,745 Deferred Tax Credits 14,321 14,990 Other Noncurrent Liabilities 106,156 98,397 Total Noncurrent Liabilities and Deferred Credits 787,995 730,059 Commitments and Contingencies (Note 14) Capitalization Long-Term Debt 963,566 943,734 Shareholders' Equity Common Stock: 50,000,000 shares authorized of $5 par value; 41,905,520 and 41,827,967 outstanding at December 31, 2025 and 2024 209,528 209,140 Additional Paid-In Capital 434,195 429,089 Retained Earnings 1,217,567 1,029,738 Accumulated Other Comprehensive Income 470 532 Total Shareholders' Equity 1,861,760 1,668,499 Total Capitalization 2,825,326 2,612,233 Total Liabilities and Shareholders' Equity $ 3,964,279 $ 3,652,082 See accompanying notes to consolidated financial statements. 48

OTTER TAIL CORPORATION CONSOLIDATED STATEMENTS OF INCOME Years Ended December 31, (in thousands, except per-share amounts) 2025 2024 2023 Operating Revenues Electric $ 566,756 $ 524,515 $ 528,359 Product Sales 737,302 806,033 820,807 Total Operating Revenues 1,304,058 1,330,548 1,349,166 Operating Expenses Electric Production Fuel 75,048 60,945 60,339 Electric Purchased Power 78,658 61,561 78,292 Electric Operating and Maintenance Expenses 184,310 190,422 191,263 Cost of Products Sold (excluding depreciation) 402,664 434,522 454,122 Nonelectric Selling, General, and Administrative Expenses 82,566 80,065 72,663 Depreciation and Amortization 118,107 107,121 97,954 Electric Property Taxes 17,023 15,662 16,614 Total Operating Expenses 958,376 950,298 971,247 Operating Income 345,682 380,250 377,919 Other Income and (Expense) Interest Expense (47,226) (41,815) (37,677) Nonservice Cost Components of Postretirement Benefits 3,334 9,609 10,597 Other Income (Expense), net 20,487 18,848 12,650 Income Before Income Taxes 322,277 366,892 363,489 Income Tax Expense 46,384 65,230 69,298 Net Income $ 275,893 $ 301,662 $ 294,191 Weighted-Average Common Shares Outstanding: Basic 41,864 41,778 41,668 Diluted 42,117 42,072 42,039 Earnings Per Share: Basic $ 6.59 $ 7.22 $ 7.06 Diluted $ 6.55 $ 7.17 $ 7.00 See accompanying notes to consolidated financial statements. 49

OTTER TAIL CORPORATION CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Years Ended December 31, (in thousands) 2025 2024 2023 Net Income $ 275,893 $ 301,662 $ 294,191 Other Comprehensive Income (Loss): Unrealized Gain on Available-for-Sale Securities, net of tax expense of $68, $128 and $51 241 386 192 Unrealized Gain (Loss) on Pension and Other Postretirement Benefit Plans, net of tax benefit (expense) of $107, $352 and $(14) (303) (1,002) 41 Total Other Comprehensive Income (Loss) (62) (616) 233 Total Comprehensive Income $ 275,831 $ 301,046 $ 294,424 See accompanying notes to consolidated financial statements. 50

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, 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 Employee Stock Purchase Plan Expenses — — (491) — — (491) Stock Issued Under Share-Based Compensation Plans, Net of Shares Withheld for Employee Taxes 77,553 388 (3,522) — — (3,134) Stock Compensation Expense — — 9,119 — — 9,119 Net Income — — — 275,893 — 275,893 Other Comprehensive Loss — — — — (62) (62) Common Dividends ($2.10 per share) — — — (88,064) — (88,064) Balance, December 31, 2025 41,905,520 $ 209,528 $ 434,195 $ 1,217,567 $ 470 $ 1,861,760 See accompanying notes to consolidated financial statements. 51

OTTER TAIL CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS Years Ended December 31, (in thousands) 2025 2024 2023 Operating Activities Net Income $ 275,893 $ 301,662 $ 294,191 Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: Depreciation and Amortization 118,107 107,121 97,954 Deferred Tax Credits (669) (182) (744) Deferred Income Taxes 33,187 23,057 13,508 Investment Gains (6,701) (5,482) (7,222) Stock Compensation Expense 9,119 9,529 7,753 Other, net (4,040) (3,111) (423) Changes in Operating Assets and Liabilities: Receivables 468 11,179 (12,750) Inventories (4,751) 3,691 (2,450) Regulatory Assets (10,779) 5,194 12,479 Other Assets (3,721) (11,640) 2,817 Accounts Payable (24,120) 14,826 (9,988) Accrued and Other Liabilities 7,257 (10,371) 6 Regulatory Liabilities 2,190 16,821 20,973 Pension and Other Postretirement Benefits (5,455) (9,563) (11,605) Net Cash Provided by Operating Activities 385,985 452,731 404,499 Investing Activities Capital Expenditures (288,068) (358,650) (287,134) Proceeds from Disposal of Investments and Other Assets 6,925 8,849 6,225 Purchases of Investments and Other Assets (9,581) (61,573) (8,378) Net Cash Used in Investing Activities (290,724) (411,374) (289,287) Financing Activities Net (Repayments) Borrowings on Short-Term Debt (9,373) (11,807) 73,218 Proceeds from Issuance of Long-Term Debt 100,000 120,000 — Dividends Paid (88,064) (78,266) (73,061) Payments for Shares Withheld for Employee Tax Obligations (3,134) (6,457) (3,088) Other, net (3,148) (549) (904) Net Cash Provided by (Used in) Financing Activities (3,719) 22,921 (3,835) Net Change in Cash and Cash Equivalents 91,542 64,278 111,377 Cash and Cash Equivalents at Beginning of Period 294,651 230,373 118,996 Cash and Cash Equivalents at End of Period $ 386,193 $ 294,651 $ 230,373 Supplemental Disclosures of Cash Flow Information Cash Paid During the Year for: Interest, net of amount capitalized $ 45,701 $ 39,484 $ 36,956 Income Taxes $ 11,093 $ 57,614 $ 46,284 Supplemental Disclosure of Noncash Investing Activities Accrued Property, Plant and Equipment Additions $ 26,129 $ 20,281 $ 13,001 See accompanying notes to consolidated financial statements 52

OTTER TAIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Summary of Significant Accounting Policies Overview Otter Tail Corporation (OTC) and its subsidiaries (collectively, the "Company," "us," "our" or "we") form a diverse, multi-platform business consisting of a vertically integrated, regulated utility with generation, transmission and distribution facilities complemented by manufacturing businesses providing metal fabrication for custom machine parts and metal components, manufacturing of extruded and thermoformed plastic products, and manufacturing of PVC pipe products. We classify our business into three segments: Electric, Manufacturing and Plastics. Note 2 includes an additional description of the segments and financial information regarding each segment. Principles of Consolidation These consolidated financial statements are presented in accordance with U.S. generally accepted accounting principles and include the accounts of OTC and its wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation except, as applicable, profits on sales to our regulated electric utility company from our nonregulated businesses, which is in accordance with the accounting requirements of regulated operations. Use of Estimates We use estimates based on the best information available in recording transactions and balances resulting from business operations. As better information becomes available or actual amounts are known, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. Reclassifications Short-term investments in the amount of $0.8 million were previously included in other current assets on our consolidated balance sheets as of December 31, 2024. This amount has been reclassified to maintain consistency and comparability between the periods presented and is now presented separately on the consolidated balance sheets. The reclassification had no impact on previously reported current or total assets, current or total liabilities, or total shareholders' equity. Regulatory Accounting Our regulated electric utility company, Otter Tail Power Company (OTP), is subject to regulation of rates and other matters by state utility commissions in Minnesota, North Dakota and South Dakota and by the 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 53

customer specifications where the terms of the contract require transfer of the completed product. Provisions for sales returns, early payment discounts and volume-based variable pricing incentives are recorded as reductions to revenue at the time revenue is recognized based on customer history, historical information and current trends. We include revenues received for shipping and handling in operating revenues. Expenses paid for shipping and handling are recorded as part of cost of products sold. Sales or other taxes collected from customers are excluded from operating revenues. Electric Segment Revenues. Most Electric segment revenues are earned from the generation, transmission and sale of electricity to retail customers at rates approved by state regulatory commissions. OTP also earns revenue from the transmission of electricity for others over the transmission assets it owns separately or jointly with other transmission service providers, under rate tariffs established by the independent transmission system operator and approved by 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. 54

Inventories Inventories are valued at the lower of cost or net realizable value. Costs for fuel, material and supply inventories of our Electric segment are determined on an average-cost basis. Costs for raw material, work in process and finished goods inventories of our Manufacturing and Plastics segments are determined on a first-in, first-out (FIFO) basis. Inventories consist of the following as of December 31, 2025 and 2024: (in thousands) 2025 2024 Raw Material, Fuel and Supplies $ 90,720 $ 82,903 Work in Process 25,381 22,637 Finished Goods 42,497 43,345 Total Inventories $ 158,598 $ 148,885 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 policies are recorded at cash surrender value and there are no restrictions on our ability to surrender the policies. Changes in the cash surrender value are recognized in earnings. 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. We evaluate these securities for impairment at each reporting date. If the fair value of a security declines below its amortized cost, management assesses whether the decline is attributable to credit- related factors. Credit-related impairments are recognized as an allowance for expected credit losses with a corresponding charge to earnings. Non-credit related unrealized losses are recorded in accumulated other comprehensive income. Unrealized gains and losses on mutual and money market funds are recognized in earnings. 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 $1.5 million in 2025, $1.9 million in 2024 and $1.9 million in 2023. 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. Estimated useful lives generally range from five years to 80 years depending on the asset type. 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. Estimated useful lives generally range from two years to 40 years depending on the asset type. 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 2025, 2024 or 2023. Maintenance and repairs are expensed as incurred. Gains or losses on asset dispositions are included in the determination of operating income. 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 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. 55

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 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, 2025 and 2024: (in thousands) 2025 2024 Cloud Computing Costs $ 20,203 $ 15,741 Accumulated Amortization (6,993) (3,796) Total Cloud Computing Costs, net $ 13,210 $ 11,945 Amortization expense of capitalized implementation costs for each of the years ended December 31, 2025, 2024 and 2023 totaled $4.3 million, $3.0 million, and $1.3 million. Leases We recognize a right-of-use lease asset and a corresponding lease liability at the lease commencement date for all long-term leases. 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 the 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 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. 56

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 obligations 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, where applicable, 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 periodic 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, 2025 and 2024, our liability to participants under these deferred compensation plans was $35.0 million and $29.1 million. Company contributions to these plans were $1.0 million, $1.3 million and $1.2 million for the years ended December 31, 2025, 2024 and 2023. Expenses recognized due to changes in our payment obligations in connection with these plans amounted to $3.9 million, $3.3 million and $3.3 million for the years ended December 31, 2025, 2024 and 2023. Stock-Based Compensation Stock-based compensation awards are measured at the grant-date fair value of the award and compensation expense is recognized on a straight-line basis over the applicable service or performance period. The service period may be limited to the period until such time that a recipient is retirement eligible as determined under the award agreement. Awards granted to employees eligible for retirement on the date of grant are expensed in the period of grant. We recognize the effects of award forfeitures as they occur. 57

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 $4.5 million and $5.5 million were recognized as of December 31, 2025 and 2024. Cash contributions paid to the two foundations during the years ended December 31, 2025, 2024 and 2023 were $5.5 million, $5.5 million, and $4.3 million. Variable Interest Entity The co-owners of Coyote Station, including OTP, are party to a Lignite Sales Agreement (LSA) with Coyote Creek Mining Company, LLC (CCMC), a subsidiary of The North American Coal Corporation. The agreement provides for the purchase of lignite coal to meet the coal supply requirements of Coyote Station through 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 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 $35 million, or OTP’s 35% share of CCMC’s unrecovered costs as of December 31, 2025. Recently Adopted Accounting Pronouncements Income Taxes. In December 2023, the FASB issued amended authoritative guidance codified in Accounting Standards Codification (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. We adopted this updated standard for the year ended December 31, 2025, on a retrospective basis and applied the new disclosure requirements. Accordingly, prior periods in our effective tax rate reconciliation disclosures in Note 13 have been reclassified to conform to the current year presentation. The adoption of this updated standard resulted in additional and modified disclosures related to our income tax expenses and income taxes paid. The adoption of this updated standard did not have an impact on our consolidated financial position or operating results. 58

Recent Accounting Pronouncements 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 new 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 of the new standard is permitted. We anticipate adopting the updated standard in our Form 10-K for the year ending December 31, 2027. Software Costs. In September 2025, the FASB issued amended authoritative guidance codified in ASC 350, Intangibles – Goodwill and Other. The amended guidance updates the cost capitalization threshold for internal-use software development costs by removing all references to software project development stages and providing new guidance on how to evaluate whether the probable-to-complete recognition threshold has been met. The updated standard is effective for our annual and interim periods beginning in 2028. Early adoption of the amended guidance is permitted. The amended guidance can be applied on a prospective, modified, or retrospective basis. We are currently evaluating the impact that the updated standard will have on our consolidated financial statements, but we do not anticipate it will have a material effect on our future financial position or operating results. Government Grants. In December 2025, the FASB issued authoritative guidance codified in ASC 832, Government Grants, which adds guidance on the recognition, measurement and presentation of government grants. The new guidance is effective for our annual periods beginning in 2029, including interim periods within that fiscal year, and can be applied on a modified prospective, modified retrospective, or full retrospective basis. We are currently evaluating the impact of this guidance on our consolidated financial statements and related 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 our vertically integrated regulated utility engaged in the production, transmission, distribution and sale of electric energy in western Minnesota, eastern North Dakota and northeastern South Dakota. Manufacturing consists of businesses which provide metal fabrication services for custom machine parts and metal components and manufacture thermoformed plastic products for use in the agriculture, construction, horticulture, industrial, lawn and garden, recreational vehicle (powersports) and other end markets. 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. Our PVC pipe is sold primarily in the western half of the United States and Canada and is generally used in municipal water infrastructure, which encompasses potable water distribution, wastewater collection and distribution and water reclamation systems. Our PVC pipe is also used within residential and commercial structures and rural water systems. 59

Segment Profit or Loss Information about each segment, including significant expenses and net income of each segment, for the years ended December 31, 2025, 2024 and 2023 are as follows: Electric Segment Operating Revenue $ 566,756 $ 524,515 $ 528,359 Production Fuel and Purchased Power 153,706 122,506 138,631 Operating and Maintenance Expenses 184,310 190,422 191,263 Depreciation and Amortization 90,168 82,136 75,330 Property Taxes 17,023 15,662 16,614 Interest Expense 43,633 38,216 33,864 Income Tax Expense (Benefit) (11,799) (1,544) 1,648 Other Segment Items(1) (7,871) (13,846) (13,415) Net Income $ 97,586 $ 90,963 $ 84,424 (1) Other segment items includes nonservice components of postretirement benefits, allowance for funds used during construction, and other expenses (income). (in thousands) 2025 2024 2023 Manufacturing Segment Operating Revenue $ 314,547 $ 342,592 $ 402,781 Cost of Goods Sold 255,275 283,390 324,245 Selling, General, and Administrative Expenses 42,372 40,110 49,396 Interest Expense 2,506 2,516 2,295 Income Tax Expense 2,877 2,895 5,390 Other Segment Items — — 1 Net Income $ 11,517 $ 13,681 $ 21,454 (in thousands) 2025 2024 2023 Plastics Segment Operating Revenue $ 422,755 $ 463,441 $ 418,026 Cost of Goods Sold 163,874 166,628 143,521 Selling, General, and Administrative Expenses 27,802 24,908 20,103 Interest Expense 685 590 602 Income Tax Expense 59,999 70,644 66,066 Other Segment Items (5) (76) (14) Net Income $ 170,400 $ 200,747 $ 187,748 (in thousands) 2025 2024 2023 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, 2025, 2024 and 2023: Capital Expenditures Electric $ 270,593 $ 301,454 $ 240,695 Manufacturing 8,903 32,159 23,284 Plastics 7,938 24,749 23,029 Corporate 634 288 126 Total Capital Expenditures $ 288,068 $ 358,650 $ 287,134 (in thousands) 2025 2024 2023 60

The following provides the identifiable assets by segment and corporate assets as of December 31, 2025 and 2024: (in thousands) 2025 2024 Identifiable Assets Electric $ 3,006,695 $ 2,785,522 Manufacturing 243,737 254,445 Plastics 185,936 186,043 Corporate 527,911 426,072 Total Identifiable Assets $ 3,964,279 $ 3,652,082 Corporate assets consist primarily of cash and cash equivalents, investments, fixed assets, and prepaid expenses. 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, 2025, 2024 and 2023: Depreciation and Amortization Electric $ 90,168 $ 82,136 $ 75,330 Manufacturing 21,282 20,393 18,495 Plastics 6,422 4,494 4,027 Corporate 235 98 102 Total Depreciation and Amortization 118,107 107,121 97,954 Interest Expense Total Interest Expense of Reportable Segments 46,824 41,322 36,761 Corporate Interest Expense 402 493 916 Total Interest Expense 47,226 41,815 37,677 Income Tax Expense (Benefit) Total Income Tax Expense of Reportable Segments 51,077 71,995 73,104 Corporate Income Tax Benefit (4,693) (6,765) (3,806) Total Income Tax Expense 46,384 65,230 69,298 Net Income (Loss) Total Net Income of Reportable Segments 279,503 305,391 293,626 Corporate Net Income (Loss) (3,610) (3,729) 565 Total Net Income $ 275,893 $ 301,662 $ 294,191 (in thousands) 2025 2024 2023 Concentrations Our Plastics segment businesses use PVC resin as a critical component within their PVC pipe manufacturing process. The domestic PVC resin industry is highly consolidated, with only four resin suppliers in the U.S. We rely on these four suppliers to source our PVC resin requirements. 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, 2025, two customers combined to account for 16% of Electric segment operating revenues, three customers combined to account for 44% of Manufacturing segment operating revenues and two customers combined to account for 47% of Plastics segment operating revenues. However, no individual customer provided 10% or more of our consolidated operating revenues. 61

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. 3. Revenue Presented below are 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, 2025, 2024 and 2023: (in thousands) 2025 2024 2023 Operating Revenues Electric Segment Retail: Residential $ 140,784 $ 133,408 $ 135,570 Retail: Commercial and Industrial 335,138 311,968 312,551 Retail: Other 8,094 7,838 7,719 Total Retail 484,016 453,214 455,840 Transmission 54,656 53,517 52,555 Wholesale 21,121 11,077 12,459 Other 6,963 6,707 7,505 Total Electric Segment 566,756 524,515 528,359 Manufacturing Segment Metal Parts 274,272 303,077 351,267 Plastic Products 33,458 32,210 41,395 Scrap Metal 6,817 7,305 10,119 Total Manufacturing Segment 314,547 342,592 402,781 Plastics Segment PVC Pipe 422,755 463,441 418,026 Total Operating Revenue 1,304,058 1,330,548 1,349,166 Less: Noncontract Revenues Included Above Electric Segment - ARP Revenues 4,418 575 (4,310) Total Operating Revenues from Contracts with Customers $ 1,299,640 $ 1,329,973 $ 1,353,476 4. Receivables Receivables as of December 31, 2025 and 2024 are as follows: (in thousands) 2025 2024 Receivables Trade $ 110,180 $ 112,169 Other 12,094 13,799 Unbilled Receivables 24,868 21,916 Total Receivables 147,142 147,884 Less Allowance for Credit Losses 1,646 1,920 Total Receivables, net of allowance for credit losses $ 145,496 $ 145,964 The following is a summary of activity in the allowance for credit losses for the years ended December 31, 2025 and 2024: (in thousands) 2025 2024 Beginning Balance $ 1,920 $ 2,522 Additions Charged to Expense 1,448 1,242 Reductions for Amounts Written Off, Net of Recoveries (1,722) (1,844) Ending Balance $ 1,646 $ 1,920 62

5. Investments The following is a summary of our investments as of December 31, 2025 and 2024: (in thousands) 2025 2024 Short-term Investments Government Debt Securities $ 53,915 $ 753 Corporate Debt Securities 396 — Total Short-term Investments 54,311 753 Long-term Investments Corporate-Owned Life Insurance Policies 49,258 47,895 Government Debt Securities 9,221 60,378 Corporate Debt Securities 924 1,628 Mutual Funds 16,727 10,653 Money Market Funds 2,666 596 Other Investments 27 27 Total Long-term Investments 78,823 121,177 Total Investments $ 133,134 $ 121,930 As of December 31, 2025, our government and corporate debt securities had maturity dates ranging from June 2026 to July 2035. During the years ended December 31, 2025, 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 $22.2 million, $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, 2025 and 2024: December 31, 2025 (in thousands) Amortized Cost Gross Unrealized Gains Gross Unrealized (Losses) Fair Value Government Debt Securities $ 62,617 $ 527 $ (8) $ 63,136 Corporate Debt Securities 1,309 12 (1) 1,320 Total Debt Securities $ 63,926 $ 539 $ (9) $ 64,456 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 Debt Securities $ 62,520 $ 433 $ (194) $ 62,759 As of December 31, 2025 and 2024, no unrealized losses on debt securities were deemed to be credit-related. The following table summarizes the fair value of debt securities available for sale by contractual maturity date as of December 31, 2025: (in thousands) 2025 Within 1 year $ 54,311 After 1 year through 5 years 9,621 After 5 years through 10 years 524 Total Debt Securities $ 64,456 63

Equity Securities The amount of net unrealized gains and losses during the years ended December 31, 2025 and 2024 on marketable equity securities still held as of December 31, 2025 and 2024 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, 2025 and 2024 and the period we expect to recover or refund such amounts: Period of 2025 2024 (in thousands) Recovery/ Refund Current Long-Term Current Long-Term Regulatory Assets Pension and Other Postretirement Benefit Plans1 See below $ 2,765 $ 72,762 $ — $ 88,161 Alternative Revenue Program Riders2 Up to 2 years 7,834 1,036 4,257 195 Deferred Income Taxes Asset lives — 9,007 — 8,944 Fuel Clause Adjustments1 Up to 1 year 6,558 — 2,218 — Derivative Instruments1 Up to 1 year 2,717 — 1,989 — Other1 Various 563 3,257 1,498 1,373 Total Regulatory Assets 20,437 86,062 9,962 98,673 Regulatory Liabilities Deferred Income Taxes Asset lives — 125,413 — 130,387 Plant Removal Obligations Asset lives — 130,686 — 126,263 Fuel Clause Adjustments Up to 1 year 1,231 — 11,432 — Alternative Revenue Program Riders Up to 1 year 9,961 — 14,255 — North Dakota PTC Refunds Asset lives — 29,169 — 20,099 Pension and Other Postretirement Benefit Plans See below 3,174 9,187 2,547 10,758 Other Various 2,234 2,943 1,073 1,421 Total Regulatory Liabilities $ 16,600 $ 297,398 $ 29,307 $ 288,928 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 December 30, 2024, the NDPSC approved a settlement agreement between OTP and certain interested parties in their 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 53.50%. The net annual revenue 64

requirement includes a net increase of $13.1 million or 6.18%. 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%. New base rates in North Dakota went into effect on March 15, 2025. South Dakota Rate Case On June 4, 2025, OTP filed a request with the SDPUC for an increase in revenue recoverable under general rates in South Dakota. In its filing, OTP requested a net increase in annual revenue of $5.7 million, or 12.50%, based on an allowed rate of return on rate base of 8.29% and an allowed ROE of 10.80% on an equity ratio of 53.54% of total capital. Through this proceeding, OTP has proposed changes to the mechanism of certain cost and investment recovery, with recovery moving from riders into base rates. Interim rates went into effect on December 1, 2025 and are subject to potential refund until the finalization of the rate case. Minnesota Rate Case On October 31, 2025, OTP filed a request with the MPUC for an increase in revenue recoverable under general rates in Minnesota. In its filing, OTP requested a net increase in annual revenue of $44.8 million, or 17.7%, based on an allowed rate of return on rate base of 7.92% and an allowed ROE of 10.65% on an equity ratio of 53.5% of total capital. The request includes, among other items, accelerated recovery of the remaining investment of the jurisdictionally allocated share of Coyote Station, which has a $4.3 million annual impact. The request for accelerated recovery is driven by the MPUC’s order in OTP’s most recent IRP to discontinue serving Minnesota customers with capacity and energy from Coyote Station by December 2031. If this part of the request is granted, we anticipate the amounts collected would be deferred and recognized over the remaining estimated useful life of the plant, which extends until 2041. The filing also included an interim rate request for a net increase in annual revenue of $31.8 million, or 12.6%. On December 23, 2025, the MPUC approved the interim rate request with a modification to exclude the impact of the accelerated recovery of the remaining investment of the jurisdictionally allocated share of Coyote Station from interim rates. The resulting interim net increase in annual revenue is $28.6 million, or 11.3%. Interim rates went into effect on January 1, 2026, and are subject to potential refund until the finalization of the rate case. 7. Property, Plant and Equipment Major classes of property, plant and equipment as of December 31, 2025 and 2024 include: (in thousands) 2025 2024 Electric Plant in Service Production $ 1,564,397 $ 1,469,008 Transmission 849,780 820,415 Distribution 828,008 726,159 General 128,492 165,361 Electric Plant in Service 3,370,677 3,180,943 Construction Work in Progress 233,978 231,890 Total Gross Electric Plant 3,604,655 3,412,833 Less Accumulated Depreciation 899,401 899,049 Net Electric Plant 2,705,254 2,513,784 Nonelectric Property, Plant and Equipment Equipment 276,966 260,307 Buildings and Leasehold Improvements 114,377 88,680 Land 13,579 13,578 Nonelectric Property, Plant and Equipment 404,922 362,565 Construction Work in Progress 12,389 40,536 Total Gross Nonelectric Property, Plant and Equipment 417,311 403,101 Less Accumulated Depreciation 245,880 224,425 Net Nonelectric Property, Plant and Equipment 171,431 178,676 Net Property, Plant and Equipment $ 2,876,685 $ 2,692,460 Depreciation expense for the years ended December 31, 2025, 2024 and 2023 totaled $116.0 million, $99.4 million and $90.8 million. 65

The following table provides OTP’s ownership percentages and amounts included in the December 31, 2025 and 2024 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, 2025 Big Stone Plant 53.9 % $ 344,723 $ 4,792 $ (143,920) $ 205,595 Coyote Station 35.0 % 188,074 3,579 (121,134) 70,519 Big Stone South–Ellendale 345 kV line 50.0 % 106,185 — (9,862) 96,323 Fargo–Monticello 345 kV line 14.2 % 78,208 248 (13,160) 65,296 Big Stone South–Brookings 345 kV line 50.0 % 53,167 — (6,462) 46,705 Brookings–Southeast Twin Cities 345 kV line 4.8 % 31,270 2 (4,277) 26,995 Bemidji–Grand Rapids 230 kV line 14.8 % 16,331 — (3,837) 12,494 Jamestown– Ellendale 345 kV line 50.0 % — 11,951 — 11,951 Alexandria–Big Oaks 345 kV line 15.8 % — 6,754 — 6,754 Big Stone South–Alexandria 345 kV line 40.0 % — 4,004 — 4,004 Oslo - Lake Ardoch 115 kV line 72.0 % 2,693 — (21) 2,672 Bison to Alexandria 345 kV 14.2 % — 14 — 14 Total $ 820,651 $ 31,344 $ (302,673) $ 549,322 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 Alexandria–Big Oaks 345 kV line 14.2 % — 417 — 417 Big Stone South–Alexandria 345 kV line 40.0 % — 2,418 — 2,418 Oslo - Lake Ardoch 115 kV line 72.0 % — 2,646 — 2,646 Total $ 815,936 $ 13,393 $ (287,481) $ 541,848 8. Intangible Assets The following table summarizes our goodwill by segment as of December 31, 2025 and 2024: (in thousands) 2025 2024 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 quarter of 2025 and 2024, indicated no impairment existed as of the test date. 66

The following table summarizes the components of our intangible assets as of December 31, 2025 and 2024: (in thousands) Gross Amount Accumulated Amortization Net Carrying Amount December 31, 2025 Customer Relationships $ 22,491 $ 17,865 $ 4,626 Other 26 10 16 Total Intangible Assets $ 22,517 $ 17,875 $ 4,642 December 31, 2024 Customer Relationships $ 22,491 $ 16,766 $ 5,725 Other 26 8 18 Total Intangible Assets $ 22,517 $ 16,774 $ 5,743 Amortization expense for these intangible assets for each of the years ended December 31, 2025, 2024 and 2023 was $1.1 million each year. Annual amortization expense for these intangible assets for the next five years is: (in thousands) 2026 2027 2028 2029 2030 Amortization Expense $ 1,092 $ 1,090 $ 554 $ 285 $ 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, 2025, 2024, and 2023 are as follows: (in thousands) 2025 2024 2023 Lease Cost Operating Lease Cost $ 6,722 $ 6,688 $ 6,309 Variable Lease Cost 1,315 1,460 1,433 Short-Term Lease Cost 2,532 2,746 2,525 Total Lease Cost $ 10,569 $ 10,894 $ 10,267 Lease Cash Flows Operating Cash Flows from Operating Leases $ 6,499 $ 6,762 $ 6,424 A summary of operating lease right-of-use lease assets and lease liabilities as of December 31, 2025 and 2024 is as follows: Right of Use Lease Assets1 $ 26,612 $ 28,179 Lease Liabilities Current2 5,042 4,776 Long-Term3 21,849 23,567 Total Lease Liabilities $ 26,891 $ 28,343 1Included in Other Noncurrent Assets in the consolidated balance sheets. 2Included in Other Current Liabilities in the consolidated balance sheets. 3Included in Other Noncurrent Liabilities in the consolidated balance sheets. (in thousands) 2025 2024 Operating lease assets obtained in exchange for new operating lease liabilities amounted to $3.6 million and $17.6 million for the years ended December 31, 2025 and 2024. 67

Maturities of lease liabilities as of December 31, 2025 for each of the next five years and in the aggregate thereafter are as follows: (in thousands) Operating Leases 2026 $ 6,557 2027 5,732 2028 4,479 2029 3,248 2030 2,579 Thereafter 10,877 Total Lease Payments 33,472 Less: Interest 6,581 Present Value of Lease Liabilities $ 26,891 The weighted-average remaining lease term and the weighted-average discount rate as of December 31, 2025 and 2024 are as follows: 2025 2024 Weighted-Average Remaining Lease Term (in years) 7.2 7.9 Weighted-Average Discount Rate 6.47 % 6.37 % 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, 2025 and 2024: 2025 2024 (in thousands) OTC OTP Total OTC OTP Total Short-Term Debt $ — $ 60,242 $ 60,242 $ — $ 69,615 $ 69,615 Current Maturities of Long-Term Debt 79,951 — 79,951 — — — Long-Term Debt — 963,566 963,566 79,900 863,834 943,734 Total Debt $ 79,951 $ 1,023,808 $ 1,103,759 $ 79,900 $ 933,449 $ 1,013,349 Short-Term Debt The following is a summary of our lines of credit as of December 31, 2025 and 2024: 2025 2024 (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 60,242 10,461 149,297 141,613 Total $ 390,000 $ 60,242 $ 10,461 $ 319,297 $ 311,613 OTC and OTP are each party to separate credit agreements (the OTC Credit Agreement and OTP Credit Agreement, respectively). The OTC Credit Agreement provides for a $170.0 million unsecured revolving line of credit, and the OTP Credit Agreement provides for a $220.0 million unsecured revolving line of credit. Both credit facilities are 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 68

ratings of the relevant borrower. The weighted-average interest rate on all outstanding borrowings as of December 31, 2025 and 2024 was 5.08% and 5.61%. Each credit facility contains a number of restrictions on the borrower, including restrictions on the ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party and engage in transactions with related parties. The agreements also require the borrower to maintain various financial covenants, as further described below. Each credit facility includes a cross-default provision whereby an event of default of other outstanding indebtedness will trigger an event of default under the agreement. The terms of each credit facility include a provision for the borrower to request, and the lenders to grant an extension of the maturity date of the facility by one year, subject to certain terms and conditions. In 2025, a one-year extension was granted, and the current maturity date of each facility is December 11, 2030. Long-Term Debt The following is a summary of outstanding long-term debt by borrower as of December 31, 2025 and 2024: (in thousands) Entity Debt Instrument Rate Maturity 2025 2024 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 60,000 OTP Series 2025A Senior Unsecured Notes 5.49% 03/27/35 50,000 — 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 60,000 OTP Series 2025B Senior Unsecured Notes 5.98% 06/05/55 50,000 — Total Long-Term Debt 1,047,000 947,000 Less: Current Maturities Net of Unamortized Debt Issuance Costs 79,951 — Less: Unamortized Long-Term Debt Issuance Costs 3,483 3,266 Total Long-Term Debt Net of Unamortized Debt Issuance Costs $ 963,566 $ 943,734 On March 27, 2025, OTP entered into a Note Purchase Agreement pursuant to which OTP issued, in a private placement transaction, $100.0 million of senior unsecured notes consisting of (a) $50.0 million of 5.49% Series 2025A Senior Unsecured Notes due March 27, 2035, and (b) $50.0 million of 5.98% Series 2025B Senior Unsecured Notes due June 5, 2055. The Series 2025A Notes were issued on March 27, 2025, upon entering into the agreement. The Series 2025B Notes were issued on June 5, 2025. 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 2025A Notes then outstanding on or after December 27, 2034, or the Series 2025B Notes then outstanding on or after December 5, 2054, 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. 69

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, 2025 for each of the next five years are as follows: (in thousands) 2026 2027 2028 2029 2030 Debt Maturities $ 80,000 $ 42,000 $ — $ 70,000 $ 50,000 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, 2025, OTC and OTP were in compliance with these financial covenants. Guaranties OTC's obligations under the terms of its Guaranteed Senior Notes are unconditionally and irrevocably guaranteed by its subsidiaries, Varistar Corporation, BTD Manufacturing, Inc., Northern Pipe Products, Inc. and Vinyltech Corporation. 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 an investment committee, comprised of members of management of the Company, 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 70

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, 2025 and 2024: Permitted Actual Allocation Asset Class Range 2025 2024 Return Enhancement 35 – 60% 40 % 41 % Risk Management 40 – 80% 60 59 Alternatives 0 – 20% — — Total 100 % 100 % Return Enhancement investments are those that seek to provide equity-like, long-term capital appreciation. Examples include equity securities, including dynamic asset allocation funds, and higher yielding fixed income securities, such as high yield bonds and emerging market debt. Risk Management investments seek to decrease downside risk or act as a hedge against plan liabilities. Examples are cash and fixed income instruments. Alternative investments seek to either provide return enhancement through long-term appreciation or risk management through decreased downside risk. The defining characteristics of these asset types are uncorrelated sources 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, 2025 and 2024 and assets measured using the net asset value (NAV) practical expedient: (in thousands) Level 1 Level 2 Level 3 NAV Total December 31, 2025 Equity Funds $ 119,208 $ — $ — $ — $ 119,208 Fixed Income Funds 190,747 — — — 190,747 Hybrid Funds 10,181 — — — 10,181 U.S. Treasury Securities 21,138 — — — 21,138 SEI Energy Debt Collective Fund — — — 903 903 Total $ 341,274 $ — $ — $ 903 $ 342,177 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 The investments held by the SEI Energy Debt Collective Fund on December 31, 2025 and 2024 consist mainly of below investment grade high yield bonds and loans of U.S. energy companies. 71

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, 2025 and 2024 and the funded status of the plans as of December 31, 2025 and 2024: Pension Benefits (Pension Plan) Pension Benefits (ESSRP) Postretirement Benefits (in thousands) 2025 2024 2025 2024 2025 2024 Change in Fair Value of Plan Assets: Fair Value of Plan Assets at January 1 $ 327,275 $ 330,479 $ — $ — $ — $ — Actual Return on Plan Assets 33,614 14,976 — — — — Company Contributions — — 2,689 2,694 2,874 1,568 Benefit Payments (18,712) (18,180) (2,689) (2,694) (4,741) (3,734) Participant Premium Payments — — — — 1,867 2,166 Fair Value of Plan Assets at December 31 $ 342,177 $ 327,275 $ — $ — $ — $ — Change in Benefit Obligation: Benefit Obligation at January 1 $ 314,010 $ 318,801 $ 35,314 $ 35,780 $ 30,003 $ 30,145 Service Cost 3,502 3,886 — — 490 490 Interest Cost 17,303 17,189 1,893 1,897 1,610 1,600 Benefit Payments (18,712) (18,180) (2,690) (2,694) (4,741) (3,734) Participant Premium Payments — — — — 1,867 2,166 Actuarial (Gain) Loss (3,782) (7,686) 550 331 5,809 (664) Benefit Obligation at December 31 312,321 314,010 35,067 35,314 35,038 30,003 Funded Status $ 29,856 $ 13,265 $ (35,067) $ (35,314) $ (35,038) $ (30,003) Amounts Recognized in Consolidated Balance Sheets at December 31: Noncurrent Assets $ 29,856 $ 13,265 $ — $ — $ — $ — Current Liabilities — — (2,691) (2,700) (3,225) (2,618) Noncurrent Liabilities — — (32,376) (32,614) (31,813) (27,385) Net Asset (Liability) $ 29,856 $ 13,265 $ (35,067) $ (35,314) $ (35,038) $ (30,003) The accumulated benefit obligation of our Pension Plan was $289.5 million and $288.5 million as of December 31, 2025 and 2024. The accumulated benefit obligation of our ESSRP was $35.1 million and $35.3 million as of December 31, 2025 and 2024. The following assumptions were used to determine benefit obligations as of December 31, 2025 and 2024: Pension Benefits (Pension Plan) Pension Benefits (ESSRP) Postretirement Benefits 2025 2024 2025 2024 2025 2024 Discount Rate 5.71 % 5.70 % 5.46 % 5.60 % 5.47 % 5.61 % Long-Term Rate of Compensation Increase 3.00 % 3.00 % n/a n/a Participants up to Age 39(1) 4.50 % 4.50 % Participants Ages 40 to 49(2) 4.50 % 4.50 % Participants Age 50 and Older(3) 3.75 % 3.75 % Healthcare Cost Immediate Trend Rate n/a n/a n/a n/a 9.00 % 6.44 % Healthcare Cost Ultimate Trend Rate n/a n/a n/a n/a 4.00 % 4.00 % Year the Rate Reaches the Ultimate Trend Rate n/a n/a n/a n/a 2051 2048 (1) Amount reflects rate of compensation increases for both union and non-union employees. (2) Amount reflects rate of compensation increases for union employees. The rate of compensation increases for non-union employees is 3.50%. (3) Amount reflects rate of compensation increases for union employees. The rate of compensation increases for non-union employees is 3.00%. The measurement of the plan asset or benefit obligation recognized for our Pension Plan, ESSRP and postretirement healthcare benefit plan included the following significant actuarial adjustments: • For the Pension Plan, an increase in the discount rate in 2025 and 2024 reduced our obligation by $0.4 million and $4.7 million. Changes in plan participant census data decreased our benefit obligation by $3.1 million in 2025. Actual 72

returns on Pension Plan assets in 2025 were $33.6 million, compared to an expected return of $24.8 million, impacting our net obligation by $8.8 million. • For the ESSRP, a decrease in the discount rate in 2025 increased our obligation by $0.5 million, and an increase in the discount rate in 2024 reduced our obligation by $0.2 million. • For the postretirement healthcare plan, a decrease in the discount rate in 2025 increased our benefit obligation by $0.4 million and an increase in our discount rate in 2024 reduced our obligation by $0.2 million. Revised estimates of healthcare cost trends, participant contribution assumptions, and other trend assumptions increased the benefit obligation by $4.5 million in 2025. Changes in plan participant census data increased our benefit obligation by $0.9 million in 2025. 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, 2025, 2024 and 2023: Pension Benefits (Pension Plan) Pension Benefits (ESSRP) Postretirement Benefits (in thousands) 2025 2024 2023 2025 2024 2023 2025 2024 2023 Service Cost $ 3,502 $ 3,886 $ 3,698 $ — $ — $ 72 $ 490 $ 490 $ 565 Interest Cost 17,303 17,189 16,436 1,893 1,897 1,889 1,610 1,600 2,416 Expected Return on Assets (24,764) (25,518) (25,914) — — — — — — Amortization of Prior Service Cost — — — — — — (3,795) (6,302) (6,649) Amortization of Net Actuarial Loss 1,341 158 — — — — — — — Net Periodic Benefit Cost $ (2,618) $ (4,285) $ (5,780) $ 1,893 $ 1,897 $ 1,961 $ (1,695) $ (4,212) $ (3,668) 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, 2025, 2024 and 2023: (in thousands) 2025 2024 2023 Net Periodic Benefit Cost $ (2,420) $ (6,600) $ (7,487) Net Amount Amortized Due to the Effect of Regulation 3,078 1,367 1,225 Net Periodic Benefit Cost Recognized $ 658 $ (5,233) $ (6,262) The following assumptions were used to determine net periodic benefit cost for the years ended December 31, 2025, 2024 and 2023: Pension Benefits (Pension Plan) Pension Benefits (ESSRP) Postretirement Benefits 2025 2024 2023 2025 2024 2023 2025 2024 2023 Discount Rate 5.70 % 5.57 % 5.51 % 5.60 % 5.53 % 5.51 % 5.61 % 5.53 % 5.52 % Long-Term Rate of Return on Plan Assets 7.00 % 7.00 % 7.00 % n/a n/a n/a n/a n/a n/a Long-Term Rate of Compensation Increase 3.00 % 3.00 % 3.00 % n/a n/a n/a Participants to Age 39 4.50 % 4.50 % 4.50 % Participants Ages 40 to 49 4.00 % 4.00 % 3.50 % Participants Age 50 and Older 3.38 % 3.38 % 2.75 % 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. 73

The following table presents the amounts not yet recognized as components of net periodic benefit cost as of December 31, 2025 and 2024: Pension Benefits (Pension Plan) Pension Benefits (ESSRP) Postretirement Benefits (in thousands) 2025 2024 2025 2024 2025 2024 Regulatory Assets (Liabilities): Unrecognized Prior Service Cost $ — $ — $ — $ — $ (9,007) $ (12,703) Unrecognized Actuarial Loss 74,332 87,868 293 292 6,735 1,121 Total $ 74,332 $ 87,868 $ 293 $ 292 $ (2,272) $ (11,582) Accumulated Other Comprehensive Income (Loss): Unrecognized Prior Service Cost $ — $ — $ — $ — $ 240 $ 339 Unrecognized Actuarial Gain (Loss) 2,374 1,937 (3,052) (2,502) 537 732 Total $ 2,374 $ 1,937 $ (3,052) $ (2,502) $ 777 $ 1,071 Cash Flows. We did not make any contributions to our Pension Plan in 2025, 2024 or 2023. As of December 31, 2025, 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) 2026 2027 2028 2029 2030 2031-2035 Projected Pension Plan Benefit Payments $ 19,685 $ 20,143 $ 20,696 $ 21,277 $ 21,635 $ 111,562 Projected ESSRP Benefit Payments 2,759 2,712 2,927 3,010 2,945 13,857 Projected Postretirement Benefit Payments 3,224 3,145 3,038 3,061 3,056 14,409 Total $ 25,668 $ 26,000 $ 26,661 $ 27,348 $ 27,636 $ 139,828 401K Plan We sponsor a 401K plan for the benefit of all corporate and subsidiary company employees. Contributions made to these plans totaled $9.7 million for 2025, $9.3 million for 2024 and $7.8 million for 2023. 12. Asset Retirement Obligations We have recognized AROs related to our coal-fired generation plants, natural gas combustion turbines, solar facility and wind turbines. The cost of AROs includes 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, 2025 and 2024, $0.1 million and $0.1 million respectively, was included in other current liabilities and $43.9 million and $42.1 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, 2025 and 2024 is as follows: (in thousands) 2025 2024 Beginning Balance $ 42,163 $ 36,477 New Obligations Recognized — 2,991 Adjustments Due to Revisions in Cash Flow Estimates — 1,098 Accrued Accretion 1,916 1,676 Settlements (92) (79) Ending Balance $ 43,987 $ 42,163 74

The provision for income taxes charged to income for the years ended December 31, 2025, 2024 and 2023 consisted of the following: (in thousands) 2025 2024 2023 Current Federal Income Taxes $ 9,107 $ 36,238 $ 41,253 State Income Taxes 4,702 6,533 15,126 Deferred Federal Income Taxes 20,802 13,078 9,832 State Income Taxes 12,385 9,979 3,676 Tax Credits North Dakota Wind Tax Credit Amortization, Net of Federal Tax (586) (586) (586) Investment Tax Credit Amortization (26) (12) (3) Total Income Tax Expense $ 46,384 $ 65,230 $ 69,298 The reconciliation of the statutory federal income tax rate to our effective tax rate for each of the years ended December 31, 2025, 2024 and 2023 is as follows: 2025 2024 2023 Income Taxes at Federal Statutory Rate $ 67,678 21.0 % $ 77,047 21.0 % $ 76,332 21.0 % Increases (Decreases) in Tax from: State and Local Taxes on Income, Net of Federal Tax1 12,696 3.9 13,081 3.6 12,933 3.6 Tax Credits: Energy Related Tax Credits (29,773) (9.2) (20,118) (5.5) (17,397) (4.8) Other (646) (0.2) (1,116) (0.3) (1,290) (0.4) Nontaxable or Nondeductible Items (125) — 276 0.1 (587) (0.2) Changes in Unrecognized Tax Benefits (26) — (364) (0.1) 566 0.2 Impact of Regulation (3,420) (1.1) (3,576) (1.0) (1,259) (0.3) Income Taxes at Effective Tax Rate $ 46,384 14.4 % $ 65,230 17.8 % $ 69,298 19.1 % 1 State taxes in Minnesota made up the majority (greater than 50%) of the tax effect in this category for each year presented. In the above table, the impact of regulation consists of excess deferred income taxes arising from the federal tax rate reduction in the 2017 Tax Cuts and Jobs Act and the impact of allowance for equity funds used during construction at OTP. Energy-related tax credits, which consist of PTCs and ITCs, North Dakota wind tax credits, which are included with state taxes in the above table, and excess deferred income taxes are returned to customers as a reduction of the rates they are charged and result in a reduction of operating revenues. Income tax payments by jurisdiction, net of refunds, were composed of the following for the years ended December 31, 2025, 2024 and 2023: (in thousands) 2025 2024 2023 Federal $ 8,061 $ 47,838 $ 38,918 State: Minnesota 2,600 8,500 5,700 All Other 432 1,276 1,666 Total Income Taxes Paid $ 11,093 $ 57,614 $ 46,284 75 13. Income Taxes Income before income taxes for the years ended December 31, 2025, 2024 and 2023 consists entirely of domestic earnings.

Deferred tax assets and liabilities were composed of the following on December 31, 2025 and 2024: (in thousands) 2025 2024 Deferred Tax Assets Employee Benefits $ 37,731 $ 37,456 Regulatory Liabilities 47,121 52,664 Tax Credit Carryforwards 15,884 18,268 Cost of Removal 34,697 35,374 Asset Retirement Obligations 11,375 10,948 Net Operating Loss Carryforward 2,485 2,289 Other 21,591 19,449 Total Deferred Tax Assets $ 170,884 $ 176,448 Deferred Tax Liabilities Differences Related to Property $ (403,559) $ (375,120) Retirement Benefits Regulatory Asset (19,520) (22,892) Pension Expense (26,720) (26,034) Other (27,016) (20,147) Total Deferred Tax Liabilities (476,815) (444,193) Total Deferred Income Taxes $ (305,931) $ (267,745) As of December 31, 2025, we had net operating loss carryforwards for state tax purposes totaling $2.5 million which expire between 2029 and 2047, state tax credits totaling $15.9 million which expire between 2041 and 2043, and federal tax credits totaling $2.0 million which expire in 2047. The following table summarizes the activity for unrecognized tax benefits for the years ended December 31, 2025, 2024 and 2023: (in thousands) 2025 2024 2023 Balance on January 1 $ 1,125 $ 1,489 $ 923 Increases (Decreases) for tax positions taken during a prior period (4) (189) 596 Increases for tax positions taken during the current period 183 188 163 Decreases as a result of a lapse of applicable statutes of limitations (214) (363) (193) Balance on December 31 $ 1,090 $ 1,125 $ 1,489 The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of December 31, 2025, with limited exceptions, we are no longer subject to examinations by taxing authorities for tax years prior to 2022 for federal and North Dakota income taxes and prior to 2021 for Minnesota state income taxes. One Big Beautiful Bill Act On July 4, 2025, broad spending and tax law legislation referred to as the One Big Beautiful Bill Act (OBBBA) was enacted in the U.S. The aspects of the law that impact our financial position and may impact our future investment opportunities include certain changes to corporate income taxes and modifications to existing renewable energy credits. The OBBBA includes changes to corporate income tax rules and regulations, including reinstating 100% bonus depreciation, immediate expensing of domestic research and development costs, and modifications to the business interest expense limitation. The effects of changes in tax laws and regulations are required to be recognized in our consolidated financial statements in the period of enactment. Accordingly, in 2025, we recognized a reduction to our current year income tax payable in the amount of $7.0 million, with a corresponding increase to our deferred income tax liability, as a result of electing to deduct previously deferred research and development costs in the current year. We also anticipate electing bonus depreciation for eligible assets in our 2025 corporate income tax return, which resulted in a reduction of our current year income tax payable and an increase to our deferred income tax liability. The OBBBA also alters the timing and eligibility of certain tax credits for renewable energy projects. Wind and solar projects that begin construction by July 4, 2026 are eligible for technology-neutral tax credits (production tax credits or investment tax credits). Projects that begin construction after July 4, 2026 must be in service by December 31, 2027 to qualify for technology-neutral tax credits. For projects that begin construction after December 31, 2025, new provisions restrict tax credit eligibility for those projects involving material assistance or effective control by a Foreign Entity of Concern, as defined in the legislation, which includes entities linked to China, Russia, Iran or North Korea. 76

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 $4.1 million, $6.0 million and $5.6 million for the years ended December 31, 2025, 2024 and 2023. Coal Purchase Commitments. OTP is party to 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 covered must be purchased under this agreement. Coal purchase costs under these two agreements totaled $50.5 million, $44.7 million and $43.7 million for the years ended December 31, 2025, 2024 and 2023. Equipment Purchase Commitments. As of December 31, 2025, OTP had commitments with third parties for the procurement, construction, delivery and installation of certain electric grid equipment which extend into 2028 and totaled approximately $53.1 million. 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 $56.4 million. Land easement costs under these agreements totaled $1.9 million, $1.8 million and $1.8 million for the years ended December 31, 2025, 2024 and 2023. Other Commitments. As of December 31, 2025, we had commitments under contracts for maintenance, software subscriptions and other services extending into 2046 which totaled approximately $23.0 million. Our future commitments as of December 31, 2025 were as follows: (in thousands) Coal Purchase Commitments Equipment Purchase Commitments Land Easement Payments Other Commitments 2026 $ 24,416 $ 12,156 $ 1,916 $ 4,426 2027 25,127 23,443 1,955 4,066 2028 25,859 17,502 1,995 3,694 2029 27,102 — 2,035 2,918 2030 25,516 — 2,077 2,419 Beyond 2030 289,196 — 46,385 5,500 Total $ 417,216 $ 53,101 $ 56,363 $ 23,023 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. On January 9, 2026, OTP completed this acquisition at a total cost of $35.7 million, including reimbursements and fees. 77

Contingencies 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 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. Class Action Lawsuits and Related Matters. Beginning in August of 2024, a series of putative federal class action lawsuits consolidated under the caption In re: PVC Pipe Antitrust Litigation (Case No. 1:24-cv-07639) were filed in the United States District Court for the Northern District of Illinois against Northern Pipe Products, Vinyltech Corporation, Otter Tail Corporation and more than twenty other PVC pipe manufacturers, as well as Oil Price Information Systems, LLC (OPIS), a reporting service that provides pricing and market intelligence in various industries, including the PVC pipe industry during the relevant period. The Court has allowed three putative classes to file complaints: a Direct Purchaser Class, a Non-Converter Seller Purchaser Class and an End-User Class. In July 2025, the Court preliminarily approved a settlement agreement among the Direct Purchaser Class, the Non-Converter Seller Purchaser Class and OPIS. The settlement agreement resolved claims against OPIS and provides for its cooperation with the plaintiffs. In August of 2025, the three putative classes each filed a first or an amended complaint alleging, among other things, that beginning in January 2017 or January 2020, depending on the class, the defendants and alleged co-conspirators conspired to fix, raise, maintain and stabilize the price of PVC municipal pipe, PVC plumbing pipe, PVC electrical pipe and PVC pipe fittings in violation of U.S. federal and state antitrust laws. The complaints allege that PVC pipe manufacturers improperly exchanged confidential information through OPIS and engaged in other indirect and direct communications with each other. Plaintiffs are seeking treble damages, injunctive relief, pre- and post-judgment interest, costs and attorneys' fees on behalf of the putative classes. On October 30, 2025, the defendants, including OTC, filed motions to dismiss. Briefings on these motions were completed in early 2026, and at this time no Court decision has been issued on the motions. In August 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 has responded to the subpoena and intends to comply with its obligations thereunder. On October 7, 2025, the DOJ filed a motion to intervene and for a partial stay of document discovery for a period of six months in In Re: PVC Pipe Antitrust Litigation, which the Court granted on October 10, 2025. 78

On September 26, 2025, a putative nation-wide class action complaint (Case No. S-257310) was filed in the Supreme Court of British Columbia, Canada against Northern Pipe, Vinyltech Corporation, Otter Tail Corporation and several other PVC pipe manufacturers, as well as OPIS. The complaint alleges that the defendants, beginning in 2021, conspired to fix, raise, maintain, and stabilize the price of PVC pipe through an information exchange, OPIS, breaching Canada's Competition Act, and creating tortious liability. The plaintiffs seek general damages, injunctive relief, pre- and post-judgment interest, punitive damages, cost, and attorneys' fees on behalf of the putative class. The Company believes there are factual and legal defenses to the allegations in the complaints and is defending itself accordingly. There remains considerable uncertainty regarding the timing or ultimate resolution of these matters. 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 in the United States and Canada or the DOJ investigation. The resolution of these matters could have a material impact on the Company’s financial position, operating results and liquidity, and it is reasonably possible that our estimate of a loss arising from these matters could change in the near term. On May 20, 2025, the Otter Tail Corporation Board of Directors received a letter from counsel submitted on behalf of a shareholder, demanding the Board investigate and take legal action against certain current and former directors and officers of the Company. The derivative demand letter includes alleged securities law violations and breach of fiduciary duties and unjust enrichment against certain current and former officers and directors of the company in connection with the matters at issue in the pending civil antitrust cases. At this time, we are unable to determine the likelihood of any outcome related to this matter. Other Contingencies. We are involved in claims, legal proceedings, investigations 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 or range of 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, 2025, other than those discussed above, will not be material. 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, 2025 or 2024. 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 2025. 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 2025, we issued 98,710 common shares under this program and no proceeds were received, as all shares issued were purchased on the open market. As of December 31, 2025, 1,330,821 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 potential restrictions under our financing agreements, certain statutory limitations or regulatory requirements, our ability to pay dividends, or our subsidiaries' ability to provide funding to OTC for the payment of dividends may be limited, 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, 2025, 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; 79

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 46.7% and 57.1%, with total capitalization not to exceed $2.4 billion based on OTP’s capital structure requirements as of December 31, 2025. As of December 31, 2025, OTP’s equity-to-total-capitalization ratio including short-term debt was 53.8% and its net assets restricted from distribution totaled approximately $896.9 million. 16. Accumulated Other Comprehensive Income (Loss) The Company's accumulated other comprehensive income (loss) consists of unamortized actuarial gains and 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, 2025, 2024 and 2023: (in thousands) Pension and Other Postretirement Benefits Net Unrealized Gain (Losses) on Available- for-Sale Securities Total Accumulated Other Comprehensive Income (Loss) Balance, December 31, 2022 $ 1,334 $ (419) $ 915 Other Comprehensive Income Before Reclassifications, net of tax 59 180 239 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss), net of tax (18) (1) 12 (2) (6) Total Other Comprehensive Income 41 192 233 Balance, December 31, 2023 1,375 (227) 1,148 Other Comprehensive Income Before Reclassifications, net of tax 501 407 908 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss), net of tax (1,503) (1) (21) (2) (1,524) Total Other Comprehensive Income (Loss) (1,002) 386 (616) Balance, December 31, 2024 373 159 532 Other Comprehensive Income Before Reclassifications, net of tax 256 246 502 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss), net of tax (559) (1) (5) (2) (564) Total Other Comprehensive Income (Loss) (303) 241 (62) Balance, December 31, 2025 $ 70 $ 400 $ 470 (1) Included in the computation of net periodic pension and other postretirement benefit costs. See Note 11 for further information. (2) Included in other income (expense), net on the accompanying consolidated statements of income. 17. Share-Based Payments Employee Stock Purchase Plan The 1999 Employee Stock Purchase Plan, as amended, 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 80

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, $0.4 million and $0.3 million for the years ended December 31, 2025, 2024 and 2023. For the years ended December 31, 2025, 2024 and 2023, the number of shares issued under the plan was 34,955, 31,252 and 26,348 shares. As of December 31, 2025, there were 171,160 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 for the granting of stock options, stock appreciation rights, restricted stock, restricted stock units, dividend equivalents, performance awards and other stock-based awards. In addition, common shares subject to any outstanding awards under our prior stock incentive plans that are forfeited, canceled or reacquired by the Company will become available for re-issuance under the 2023 Stock Incentive Plan. As of December 31, 2025, 695,826 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 $8.7 million, $9.1 million and $7.4 million for the years ended December 31, 2025, 2024 and 2023. The related income tax benefit recognized for these periods amounted to $2.0 million, $2.7 million and $1.6 million. Restricted Stock Awards. Restricted stock awards are granted to executive officers and other key employees and members of the Company's Board of Directors. The awards vest, depending on award recipient, either ratably over a period of three to four years or cliff vest after four years. Vesting is accelerated in certain circumstances, including upon retirement. Awards granted to members of the Board of Directors are issued and outstanding upon grant and carry the same voting and dividend rights of unrestricted outstanding common stock. Awards granted to executive officers 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, 2025: Shares Average Grant-Date Fair Value Nonvested, Beginning of Year 143,417 $ 68.47 Granted 58,185 74.20 Vested (47,593) 59.74 Forfeited (8,120) 68.56 Nonvested, End of Year 145,889 $ 73.60 The weighted-average grant-date fair value of granted awards was $74.20, $85.25 and $68.03 during the years ended December 31, 2025, 2024 and 2023. The fair value of vested awards was $3.6 million, $5.1 million and $3.1 million during the years ended December 31, 2025, 2024 and 2023. As of December 31, 2025, there was $3.7 million of unrecognized compensation cost for unvested restricted stock awards to be recognized over a weighted-average period of 1.86 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, 2025, 2024 and 2023 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, 2025, 2024 and 2023 was determined using a Monte Carlo fair value simulation model 81

incorporating the following assumptions: 2025 2024 2023 Risk-free interest rate 4.28 % 4.16 % 4.15 % Expected term (in years) 3.00 3.00 3.00 Expected volatility 30.30 % 35.10 % 34.00 % Dividend yield 2.50 % 2.40 % 2.50 % The risk-free interest rate was derived from yields on U.S. government bonds of a similar term. The expected term of the award is equal to the three-year performance period. Expected volatility was estimated based on actual historical volatility of our common stock over a three-year period. Dividend yield was estimated based on historic and future yield estimates. The following is a summary of stock performance award activity for the year ended December 31, 2025 (share amounts reflect awards at target): Shares Average Grant-Date Fair Value Nonvested, Beginning of Year 144,800 $ 68.85 Granted 57,000 73.90 Vested (49,000) 53.93 Forfeited — — Nonvested, End of Year 152,800 $ 75.52 The weighted-average grant-date fair value of granted awards was $73.90, $94.45 and $61.97 during the years ended December 31, 2025, 2024 and 2023. The fair value of vested awards was $5.5 million, $12.3 million and $5.3 million during the years ended December 31, 2025, 2024 and 2023. As of December 31, 2025, there was $0.2 million of unrecognized compensation cost of unvested stock performance awards to be recognized over a weighted-average period of 0.96 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, 2025, 2024 and 2023: (in thousands) 2025 2024 2023 Weighted Average Common Shares Outstanding – Basic 41,864 41,778 41,668 Effect of Dilutive Securities: Stock Performance Awards 155 196 269 Restricted Stock Awards 96 96 100 Employee Stock Purchase Plan Shares 2 2 2 Dilutive Effect of Potential Common Shares 253 294 371 Weighted Average Common Shares Outstanding – Diluted 42,117 42,072 42,039 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, 2025, 2024 and 2023. 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 82

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, 2025 and 2024, OTP had multiple outstanding pay-fixed, receive-variable swap agreements. The contracts outstanding as of December 31, 2025 had various settlement dates throughout 2026. The following presents the notional amounts and fair value of our derivative instruments as of December 31, 2025 and 2024: (in thousands) 2025 2024 Megawatt hours of electricity 311 167 Derivative Assets: Other Current Assets $ 124 $ — Other Noncurrent Assets — — Total Derivative Assets 124 — Derivative Liabilities: Other Current Liabilities $ 2,717 $ 1,989 Other Noncurrent Liabilities — — Total Derivative Liabilities $ 2,717 $ 1,989 During the years ended December 31, 2025 and 2024, contracts matured and were settled in an aggregate amount of a $2.1 million loss and a $3.5 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, 2025 and 2024 classified by the input method used to measure fair value: (in thousands) Level 1 Level 2 Level 3 December 31, 2025 Assets Investments: Money Market Funds $ 2,666 $ — $ — Mutual Funds 16,727 — — Corporate Debt Securities — 1,320 — Government Debt Securities — 63,136 — Derivative Instruments — 124 — Total Assets 19,393 64,580 — Liabilities Derivative Instruments — 2,717 — Total Liabilities $ — $ 2,717 $ — 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 $ — 83

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. 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, 2025 and 2024: December 31, 2025 December 31, 2024 (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value Assets: Cash and Cash Equivalents $ 386,193 $ 386,193 $ 294,651 $ 294,651 Total 386,193 386,193 294,651 294,651 Liabilities: Short-Term Debt 60,242 60,242 69,615 69,615 Long-Term Debt 1,043,517 923,639 943,734 806,826 Total $ 1,103,759 $ 983,881 $ 1,013,349 $ 876,441 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, 2025, 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, 2025. 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, 2025 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. 84

In order to assure the consolidated financial statements are prepared in conformance with generally accepted accounting principles, management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). These internal controls are designed only to provide reasonable assurance, on a cost- effective basis, that transactions are carried out in accordance with management’s authorizations and assets are safeguarded against loss from unauthorized use or disposition. Management has completed its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2025. 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, 2025, 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. 85

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 2026 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 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 2026 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 2026 Annual Meeting. The following table sets forth information as of December 31, 2025 about the Company’s common stock that may be issued under all of 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 346,854 '(1) N/A 695,826 '(2) 1999 Employee Stock Purchase Plan — N/A 171,160 '(3) Equity compensation plans not approved by security holders — — — Total 346,854 — 866,986 (1) Includes 85,500, 65,100 and 78,600 performance-based share awards, assuming a maximum payout, granted in 2025, 2024 and 2023, respectively, and 117,654 restricted stock units outstanding as of December 31, 2025. (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. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE The information required by this Item is incorporated by reference to the information under “Policy and Procedures Regarding Transactions with Related Persons,” “Election of Directors” and "Director Independence Determinations" in the Company’s definitive Proxy Statement for the 2026 Annual Meeting. 86

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 2026 Annual Meeting. 87

PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 1. Financial Statements Page Report of Independent Registered Public Accounting Firm 46 Consolidated Balance Sheets 48 Consolidated Statements of Income 49 Consolidated Statements of Comprehensive Income 50 Consolidated Statements of Shareholders’ Equity 51 Consolidated Statements of Cash Flows 52 Notes to Consolidated Financial Statements 53 2. Financial Statement Schedules Schedule I - Condensed Financial Information of Registrant Schedule II - Valuation and Qualifying Accounts and Reserves 88

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT OTTER TAIL CORPORATION (PARENT COMPANY) CONDENSED BALANCE SHEETS December 31, (in thousands) 2025 2024 Assets Current Assets Cash and Cash Equivalents $ 384,479 $ 291,575 Accounts Receivable from Subsidiaries 2,585 5,642 Interest Receivable from Subsidiaries 117 117 Notes Receivable from Subsidiaries 3,037 4,706 Investments 53,915 — Other Current Assets 8,741 3,538 Total Current Assets 452,874 305,578 Noncurrent Assets Investments in Subsidiaries 2,302,613 2,006,239 Notes Receivable from Subsidiaries 78,900 78,900 Investments 62,529 106,677 Deferred Income Taxes 31,264 69,781 Other Noncurrent Assets 3,386 2,380 Total Assets $ 2,931,566 $ 2,569,555 Liabilities and Stockholders' Equity Current Liabilities Current Maturities of Long-Term Debt $ 79,951 $ — Accounts Payable to Subsidiaries 8 7 Notes Payable to Subsidiaries 915,775 752,625 Other 18,762 19,100 Total Current Liabilities 1,014,496 771,732 Other Noncurrent Liabilities 55,310 49,424 Commitments and Contingencies Capitalization Long-Term Debt — 79,900 Common Stockholders' Equity 1,861,760 1,668,499 Total Capitalization 1,861,760 1,748,399 Total Liabilities and Stockholders' Equity $ 2,931,566 $ 2,569,555 See accompanying notes to condensed financial statements. 89

OTTER TAIL CORPORATION (PARENT COMPANY) CONDENSED STATEMENTS OF INCOME Years Ended December 31, (in thousands) 2025 2024 2023 Income Equity Income in Earnings of Subsidiaries $ 280,159 $ 304,525 $ 294,467 Interest Income from Subsidiaries 3,191 3,107 2,898 Other Income 16,437 15,085 10,496 Total Income 299,787 322,717 307,861 Expense Nonelectric Selling, General, and Administrative Expenses 24,072 23,016 12,816 Interest Expense 3,593 3,599 3,813 Interest Expense from Subsidiaries 5 5 6 Nonservice Cost Components of Postretirement Benefits 1,091 970 1,063 Total Expense 28,761 27,590 17,698 Income Before Income Taxes 271,026 295,127 290,163 Income Tax Benefit 4,867 6,535 4,028 Net Income $ 275,893 $ 301,662 $ 294,191 See accompanying notes to condensed financial statements. 90

OTTER TAIL CORPORATION (PARENT COMPANY) CONDENSED STATEMENTS OF CASH FLOWS Years Ended December 31, (in thousands) 2025 2024 2023 Cash Flows from Operating Activities Net Cash Provided by Operating Activities $ 127,484 $ 76,333 $ 77,139 Cash Flows from Investing Activities Investment in Subsidiaries (105,000) (55,000) (40,000) Purchases of Investments and Other Assets (3,311) (53,085) (1,754) Other, net 782 1,394 1,686 Net Cash Used in Investing Activities (107,529) (106,691) (40,068) Cash Flows from Financing Activities Borrowings from Subsidiaries 164,819 179,247 148,308 Payments for Shares Withheld for Employee Tax Obligations (3,134) (6,457) (3,088) Dividends Paid (88,064) (78,265) (73,061) Other, net (672) (729) (339) Net Cash Provided by Financing Activities 72,949 93,796 71,820 Net Change in Cash and Cash Equivalents 92,904 63,438 108,891 Cash and Cash Equivalents at Beginning of Period 291,575 228,137 119,246 Cash and Cash Equivalents at End of Period $ 384,479 $ 291,575 $ 228,137 See accompanying notes to condensed financial statements. 91

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, 2025 and 2024 are as follows: (in thousands) Accounts Receivable Interest Receivable Current Notes Receivable Long-Term Notes Receivable Accounts Payable Current Notes Payable December 31, 2025 Otter Tail Power Company $ 2,434 $ — $ — $ — $ 8 $ — Northern Pipe Products, Inc. — 7 — 5,000 — 51,025 Vinyltech Corporation — 17 — 11,500 — 70,353 BTD Manufacturing, Inc. — 78 — 52,000 — 29,382 T.O. Plastics, Inc. 38 15 3,037 10,400 — — Varistar Corporation — — — — — 765,015 Otter Tail Assurance Limited 113 — — — — — Total $ 2,585 $ 117 $ 3,037 $ 78,900 $ 8 $ 915,775 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 Dividends Dividends paid to OTC (the Parent) from its subsidiaries were as follows: (in thousands) 2025 2024 2023 Cash Dividends Paid to Parent by Subsidiaries $ 88,984 $ 78,191 $ 72,982 See OTC’s notes to consolidated financial statements in Part II, Item 8 for other disclosures. 92

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, 2025, 2024 and 2023: (in thousands) Balance, January 1 Charged to Cost and Expenses Deductions(1) Balance, December 31 Allowance for Credit Losses 2025 $ 1,920 $ 1,448 $ (1,722) $ 1,646 2024 2,522 1,242 (1,844) 1,920 2023 1,648 2,014 (1,140) 2,522 (1)Amounts reflect deductions to the allowance for amounts written-off, net of recoveries. 93

3. Exhibits The following Exhibits are filed as part of, or incorporated by reference into, this report. 3.1 Third Restated Articles of Incorporation, dated April 12, 2021 3.2 Restated Bylaws, dated April 12, 2021 4.1 Description of Securities 10.1.0 Note Purchase Agreement, dated as of August 20, 2007, between Otter Tail Power Company and the Purchasers named therein 10.1.1 First Amendment, dated as of December 14, 2007, to Note Purchase Agreement, dated as of August 20, 2007, between Otter Tail Power Company and the Purchasers named therein 10.1.2 Second Amendment, dated as of September 11, 2008, to Note Purchase Agreement, dated as of August 20, 2007, between Otter Tail Power Company and the Purchasers named therein 10.1.3 Third Amendment, dated as of June 26, 2009, to Note Purchase Agreement dated as of August 20, 2007, between Otter Tail Power Company and the Purchasers named therein 10.2 Note Purchase Agreement dated as of August 14, 2013 between Otter Tail Power Company and the Purchasers named therein 10.3 Note Purchase Agreement dated as of September 23, 2016 between Otter Tail Corporation and the Purchasers named therein 10.4 Note Purchase Agreement dated as of November 14, 2017 between Otter Tail Power Company and the Purchasers named therein 10.5 Note Purchase Agreement dated as of September 12, 2019 between Otter Tail Power Company and the Purchasers named therein 10.6 Note Purchase Agreement dated as of June 10, 2021 between Otter Tail Power Company and the Purchasers named therein 10.7 Note Purchase Agreement dated as of March 28, 2024 between Otter Tail Power Company and the Purchasers named therein 10.8 Note Purchase Agreement dated as of March 27, 2025 between Otter Tail Power Company and the Purchasers named therein 10.9 Sixth Amended and Restated Credit Agreement, dated as of December 11, 2024, by and between Otter Tail Corporation, as Borrower, and the banks named therein, with U.S. Bank National Association, as Administrative Agent 10.10 Fifth Amended and Restated Credit Agreement, dated as of December 11, 2024, by and between Otter Tail Power Company, as Borrower, and the banks named therein, with U.S. Bank Nation Association, as Administration Agent 10.11.0 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 10.11.1 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 10.11.2 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 10.11.3 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 10.11.4 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 10.11.5 Supplemental Agreement No. 4 to Agreement for Sharing Ownership of Big Stone Plant (dated as of April 24, 2003) 10.11.6 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 10.12 Big Stone South–Ellendale Project Ownership Agreement dated as of June 12, 2015 between Otter Tail Power Company, a wholly owned subsidiary of Otter Tail Corporation, and Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc.** 10.13.0 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 10.13.1 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 10.13.2 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 10.13.3 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 10.13.4 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 10.13.5 Amendment, dated as of June 14, 2001, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1 10.13.6 Amendment, dated as of April 24, 2003, to Agreement for Sharing Ownership of Coyote Generating Unit No. 1 No. Description 94

10.14.0 Lignite Sales Agreement between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., Northwestern Corporation, dated as of October 10, 2012** 10.14.1 First Amendment to Lignite Sales Agreement dated as of January 30, 2014 among Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., NorthWestern Corporation and Coyote Creek Mining Company, L.L.C. 10.14.2 Second Amendment to Lignite Sales Agreement dated as of March 16, 2015 among Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., NorthWestern Corporation and Coyote Creek Mining Company, L.L.C. 10.15 Executive Survivor and Supplemental Retirement Plan (2020 Restatement)* 10.16 Nonqualified Retirement Plan (2021 Restatement)* 10.17 Otter Tail Corporation Executive Restoration Plus Plan, 2020 Restatement* 10.18 1999 Employee Stock Purchase Plan, As Amended (2025) 10.19 2014 Stock Incentive Plan* 10.20 2023 Stock Incentive Plan* 10.21 2026 Executive Annual Incentive Plan* 10.22 Form of Executive Performance Share Award Agreement (Executives)* 10.23 Form of Executive Performance Share Award Agreement - Stock Settlement (Executives)* 10.24 Form of Executive Performance Share Award Agreement - Cash Settlement (Executives)* 10.25 Form of Restricted Stock Unit Award Agreement (Executives)* 10.26 Form of Restricted Stock Unit Award Agreement - Stock Settlement (Executives)* 10.27 Form of Restricted Stock Unit Award Agreement - Cash Settlement (Executives)* 10.28 Form of Restricted Stock Award Agreement (Directors)* 10.29 Summary of Non-Employee Director Compensation (2025)* 10.30 Change in Control Severance Agreement, Chuck MacFarlane, dated February 24, 2012* 10.31 Change in Control Severance Agreement, Timothy Rogelstad, dated April 14, 2014* 10.32 Change in Control Severance Agreement, Paul Knutson, dated December 17, 2012* 10.33 Change in Control Severance Agreement, John Abbott, dated April 13, 2015* 10.34 Change in Control Severance Agreement, Todd Wahlund, dated January 1, 2024* 10.35 Change in Control Severance Agreement, Jennifer Smestad, dated January 1, 2018* 10.36 Form of Change in Control Severance Agreement (2023)* 10.37 Otter Tail Corporation Executive Severance Plan (2024)* 19 Insider Trading and Pre-Clearance Policy 21 Subsidiaries of Registrant 23 Consent of Deloitte & Touche LLP 24 Power of Attorney 31.1 Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 31.2 Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 32.1 Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 32.2 Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 97 Incentive Compensation Recovery Policy 101.SCH Inline XBRL Taxonomy Extension Schema Document 101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document 101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document 101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document 101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document 104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) No. Description *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. 95

ITEM 16. FORM 10-K SUMMARY None. 96

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 18, 2026 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 18, 2026 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 ) 97

Shareholder Information Annual Meeting The 2026 Annual meeting of Shareholders will be held virtually on Monday, April 13, 2026 at 10:00 a.m. (CDT). Join online at www.virtualshareholdermeeting.com/OTTR2026. Corporate Headquarters 215 South Cascade Street P.O. Box 496 Fergus Falls, MN 56538 Stock Exchange Listing Trading Symbol: OTTR Listed on Nasdaq Global Select Market Dividends Otter Tail Corporation has paid dividends on our common shares since 1938 without interruption or reduction. Common stock dividends are paid quarterly on or around March, June, September and December 10. Transfer Agent EQ Shareowner Services P.O. Box 64854 St. Paul, MN 55164 Phone: 866-605-8638 Website: www.shareowneronline.com Otter Tail Corporation Shareholder Services Email: sharesvc@ottertail.com Dividend Reinvestment and Share Purchase Plan Our Dividend Reinvestment and Share Purchase Plan provides shareholders of record the opportunity to purchase shares of Otter Tail Corporation common stock and reinvest dividends without incurring brokerage fees or service charges. The plan is sponsored and administered by EQ Shareowner Services. For more information, contact EQ Shareowner Services. Stock Certificates and Direct Registration System (DRS) Physical stock certificates can be difficult to manage and costly to replace if lost. To simplify ownership and reduce risk, we encourage shareholders to convert their shares to book-entry form through DRS. DRS provides secure, paperless recordkeeping and makes managing your investment more efficient. Contact EQ Shareowner Services for assistance. Shareholder Information and Assistance Shareholders of record have electronic access to their accounts by visiting www.shareowneronline.com. Shareowner Online allows shareholders to view their account balance, dividend information, reinvestment details and more. EQ Shareowner Services maintains shareholder account information. For assistance with individual stock records, transfers, lost certificates, name or address changes or dividend payments, contact EQ Shareowner Services. Otter Tail Corporation financial reports, including filings with the Securities and Exchange Commission, and other information are available online at www.ottertail.com.

Annual Report 2025 S H A R E H O L D E R S E RV I C ES 215 South Cascade Street P.O. Box 496 Fergus Falls, MN 56538 Email: sharesvc@ottertail.com www.ottertail.com | Nasdaq: OTTR O TTER TA IL CO RPO RATIO N 2025 A N N U A L REPO RT