Ormat Technologies, Inc.: Form 10-K for the period ended Dec 31, 2025

Overview

We are a leading vertically integrated company primarily engaged in the geothermal power business. We leverage our core capabilities, proprietary technologies, and global presence to expand our activities in conventional geothermal development, recovered energy generation and emerging geothermal technologies, including piloting of new EGS technologies. In addition, we are expanding into different complementary energy solutions, including stand alone utility scale energy storage services and solar PV generation (including hybrid geothermal and solar PV as well as solar plus energy storage). Our objective is to become a leading global provider of renewable energy and to help mitigate climate change by providing reliable base-load and flexible alternatives to carbon-intensive energy sources. To support this objective, we have adopted a strategic plan focused on several key initiatives to expand our business, including advancing EGS through collaborations and pilot projects, diversifying our renewable energy offerings, and leveraging our operational expertise to drive long-term growth.

We currently conduct our business activities in three business segments:

• Electricity Segment. In the Electricity segment, we develop, build, own and operate geothermal, solar PV and recovered energy-based power plants in the United States and geothermal power plants in other countries around the world and sell the electricity they generate. Since the beginning of 2025, we have increased our commercial operation by 115MW from geothermal and solar PV power plants, achieved through both organic growth and M&A. Through organic development, 6MW were contributed by the repowering of the Beowawe geothermal plant, 17MW, our proportional share, by the Ijen geothermal facility in Indonesia, and 42MW by the Arrowleaf solar PV plant, which is connected to an energy storage system. Furthermore, we acquired an additional 20MW from the Blue Mountain geothermal plant after closing a transaction with Cyrq Energy in June 2025 and another 30MW from a solar PV plant connected to a battery energy storage system in Hawaii, purchased from Innergex Renewable Energy Inc. in January 2026.
• Product Segment. In the Product segment, we design, manufacture and sell equipment for geothermal and recovered energy-based electricity generation and provide services relating to the engineering, procurement and construction of geothermal and recovered energy-based power plants. During 2025, we signed new contracts that were added to our backlog, and secured $103.5 million of anticipated Product revenues, the majority of which we expect to be recognized over the next two years. In addition, in January 2026 we added approximately $100.0 million to the backlog related to the TOPP2 project in New Zealand that was transferred to third party at COD and which we expect to be recorded as revenues in the first quarter of 2026.
• Energy Storage Segment. In the Energy Storage segment, we own and operate grid-connected, stand alone In Front of the Meter (IFM) BESS facilities, which provide capacity, energy and ancillary services directly to the electric grid. We operate our facilities in three main areas in the U.S., California, Texas and the East Coast (mainly in the PJM market) and generate our revenues mainly from the sale of ancillary services in the merchant market and /or tolling agreements and RA contracts. Since the beginning of 2025, we commissioned two energy storage facilities with a total capacity of 95MW/260 MWh, one in Texas and the second that is connected to the Solar PV power plant in California. In addition, we acquired a 30MW/120MWh battery energy storage system connected to a solar PV power plant in Hawaii from Innergex Renewable Energy Inc, in January 2026.

The following chart sets forth a breakdown of our revenues for each of the years ended December 31, 2025 and 2024:

The following chart sets forth the geographical breakdown of revenues attributable to our Electricity and Product segments for each of the years ended December 31, 2025 and 2024:

The revenues attributable to our Energy Storage segment for each of the years ended December 31, 2025 and 2024 were 100% generated in the United States.

Our Electricity Segment

Our Company-owned power plants include both power plants that we have built and acquired. The substantial majority of these power plants produce electricity from geothermal energy sources. Geothermal energy is a clean, renewable and generally sustainable form of energy derived from the natural heat of the earth. Unlike electricity produced by burning fossil fuels, geothermal energy is produced without emissions of certain pollutants such as nitrogen oxide, and with far lower emissions of other pollutants such as carbon dioxide. As a result, electricity produced from geothermal energy contributes significantly less to negative climate change and local and regional incidences of acid rain than energy produced by burning fossil fuels. Additionally, unlike wind or solar power plants, geothermal power plants can generally operate 24 hours a day, therefore providing base-load electricity services. Geothermal power plants can also be custom built to provide a range of electricity services such as baseload, voltage regulation, reserve and flexible capacity.

We own and operate geothermal and solar PV hybrid projects, solar PV plus storage facilities and standalone solar PV power plants with similar projects currently under construction. In our hybrid projects, electricity generated from the solar PV power plant is used to offset the equipment’s energy use at the geothermal facility, increasing the net geothermal energy delivered to the grid. Our standalone solar PV power plants sell their output under long term PPAs.

We also construct, own, and operate 50MW of recovered energy-based power plants. Recovered energy is derived from residual heat generated as a by-product of gas turbine-driven compressor stations, solar thermal units and industrial processes such as cement manufacturing. This heat, which would otherwise be wasted, is captured and used to generate electricity without burning additional fuel or producing additional emissions.

Our geothermal power plants sell substantially all of their output under long-term PPAs, most with fixed prices, denominated in or linked to the U.S. dollar or Euro. As of December 31, 2025, these contracts had a weighted average remaining term of approximately 14 years based on contributions to segment revenue. The counterparties to our PPAs in the United States have a credit rating of between Baa1 to Ba2 (stable) by Moody's and AA+ to B+ by S&P. The purchasers of electricity from our foreign power plants are primarily state-owned entities in countries with below investment grade ratings.

Power Plants in Operation

We own and operate 35 power plants and complexes globally, with an aggregate generating capacity of 1,340MW, comprising geothermal, REG and solar facilities as listed below. Geothermal represents 81.3% of our Electricity Segment generating capacity. In 2025, our geothermal and REG power plants achieved capacity factors of 84% and 70%, respectively, significantly exceeding the 20%-30% capacity factors typical of wind and solar projects.

The table below summarizes certain key non-financial information relating to our power plants and complexes as of February 25, 2026. Generating capacity figures have been updated from our 2024 disclosure to reflect changes in resource temperature and other factors that impact resource capabilities:

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1. We have a controlling interest in and we operate all of our power plants, except for Sarulla and Ijen both in Indonesia. In the U.S., certain other financial institutions hold equity interests in seven of our subsidiaries: (i) ORNI 41, which owns the McGinness Hills Phase 3 located in Nevada; (ii) ORNI 43, which owns the Tungsten Mountain geothermal power plant located in Nevada; (iii) Steamboat Hills, LLC, which owns the Steamboat Hills power plant located in Nevada; (iv) CD4 partnership that owns the CD4 power plant, under Mammoth Complex, in California; (v) ORNI 36, which owns the North Valley power plant, under San Emidio complex, located in Nevada, (vi) Heber Geothermal Company, LLC and OrHeber2, LLC, which own the Heber 1 and Heber 2 geothermal power plants located in California, respectively; and (vii) Vessi 38, LLC and ORNI 30, LLC, which own Lower Rio energy storage facility located in Texas and Arrowleaf solar plus energy storage facility located in

California, respectively. In the table above, we list these power plants as being 100% owned because all of the generating capacity is owned by these subsidiaries and we control the operation of the power plants. The nature of the equity interests held by the financial institution is described below in Item 8 — “Financial Statements and Supplementary Data" under Note 12.

We own a 63.75% equity interest in the Bouillante power plant, a 97% equity interest in the Zunil power plant, a 60% equity interest in the Neal Hot Spring power plant, and a 63.25% direct equity interest in the Puna plant. We list 100% of the generating capacity of the Bouillante power plant, the Zunil power plant, the Neal Hot Springs power plant and the Puna power plant in the table above because we control their operations. We list our 12.75% share of the generating capacity of the Sarulla complex and 49% of the generating capacity of the Ijen power plant as we own minority interests in these projects. Revenues from the Sarulla complex and from the Ijen power plant are not consolidated and are presented under “Equity in earnings (losses) of investees, net” in our consolidated financial statements.

2. References to generating capacity generally refer to gross generating capacity less auxiliary power. We determine the generating capacity of these power plants by taking into account resource and power plant capabilities. In any given year, the actual power generation of a particular power plant may differ from that power plant’s generating capacity due to variations in ambient temperature, the availability of the geothermal resource, and operational issues affecting performance during that year.

3. Capacity factor is generally calculated as the actual MWh generation divided by the maximum potential generation (generating capacity multiplied by 8,760 hours). In the case of curtailments by the grid operator the generated MWh are taken into account in our calculation although the curtailed MWh were not sold to the grid.

4. Generating capacity reduced to reflect cooling experienced in the resource.

5. This is a hybrid geothermal and solar power plant that uses the solar energy for geothermal power plant auxiliary power. The solar PV facilities are presented separately in the table above.

6. The San Emidio complex includes 25MW from North Valley that commenced commercial operation in May 2023.

7. The Blue Mountain power plant was acquired and added to our portfolio in June 2025. The Power plant generating capacity increased due to better performance than expected.

8. The OREG power plants are not operating at full capacity due to low run time of the compressor stations that serve as the power plants heat source. This has resulted in lower power generation. During the fourth quarter of 2025, the company deemed that one of its customers is expected to terminate the waste heat agreement related to the OREG 2 facility.

9. The 35MW Ijen power plant in Indonesia commenced operation in February 2025. Our share is 17MW (49%).

10. The Arrowleaf solar PV plus energy storage facility commenced operation in December 2025. The solar PV generating capacity, attached to the storage facility, is included in the Electricity segment portfolio, however, 100% of the revenue is recorded under the Energy Storage segment.

11. The Hoku solar PV plus energy storage facility in Hawaii was acquired in January 2026 from Innergex Renewable Energy Inc. The solar PV generating capacity, attached to the storage facility, is included in the Electricity segment portfolio, however, 100% of the revenue is recorded under the Energy Storage segment.

12. The total Electricity segment portfolio presented in the table above is as of February 25, 2026. The total Electricity segment portfolio as of December 31, 2025 stood at 1,310MW.

New Power Plants

We are currently constructing new power plants and expanding existing facilities. We have released for construction geothermal and solar PV projects with generating capacity of 136.5MW worldwide. In addition, we disclosed 24MW of geothermal and solar PV projects in various stages of development in the United States.

We hold substantial land positions across 34 prospects in the United States and 16 prospects internationally (Ethiopia, Guatemala, Honduras, Indonesia and New Zealand) that we expect will support future geothermal development. These positions consist of leases, geothermal exploration concessions, and lease options. We have commenced or plan to start exploration activity on many of these prospects.

We expect to add 310MW to 410MW of generating capacity in the Electricity Segment, reaching a total capacity of 1.65 to 1.75 GW by 2028.

Our Product Segment

We design, manufacture and sell electricity generation products and provide related services as described below. We also provide cementing services for well drilling to third parties. We primarily manufacture products to fulfill customer orders, though we also produce inventory for future projects, whether owned by us or by third parties.

Power Units for Geothermal Power Plants

We design, manufacture and sell power units for geothermal electricity generation, referred to as OECs. Our customers include contractors, developers, owners and operators of geothermal power plants.

We also support EGS, which enable geothermal power generation in areas lacking sufficient natural underground reservoirs. This technology has the potential to expand the geographic reach of geothermal energy while maintaining its renewable characteristics. Our OECs are engineered to operate effectively under EGS conditions.

Power Units for Recovered Energy-Based Power Generation

We design, manufacture and sell power units that generate electricity from recovered energy, commonly known as “waste heat.” Our customers include owners and operators of interstate natural gas pipelines, gas processing plants, cement plants and other energy-intensive industrial facilities.

EPC of Power Plants

We provide turnkey EPC services for geothermal and recovered energy power plants using power units we design and manufacture. Our customers include geothermal power plant owners and operators of energy-intensive industrial facilities.

Production Pumps

We design, manufacture and sell geothermal production pumps to third-party power plant operators and have identified geothermal district heating as a potential market.

Our Energy Storage Segment

Our Energy Storage segment has grown consistently since 2019 and remains a strategic priority for investment and expansion.

We own and operate 19 BESS projects in the U.S. with an aggregate capacity of 415MW/1,038MWh. The following table summarizes key information regarding these projects as of February 25, 2026:

New BESS Projects

We are constructing 8 additional energy storage projects with a total capacity of 410MW/1,540MWh in California, Texas and Israel. In addition, we have an approximately 2.7GW/10.0GWh pipeline of potential projects in various stages of development across the United States, supporting our target of 950–1,050MW/2,500–2,900MWh of energy storage capacity by year-end 2028. We plan to continue leveraging our project development and finance experience, EPC expertise, and utility relationships to develop additional BESS projects.

Business Strategy

Our strategy focuses on developing a geographically balanced portfolio of geothermal, energy storage, and solar PV while strengthening our leadership in geothermal energy to become a leading global renewable energy provider.

In this evolving market, our strategy is to build on our existing capabilities and core competencies while expanding our ability to compete in next-generation geothermal markets, including enhanced geothermal systems (“EGS”) and other advanced solutions. These technologies have the potential to increase the scale of geothermal power plants, broaden geographic applicability, and expand the addressable market for firm, renewable power.

We plan to pursue next-generation geothermal opportunities through a disciplined approach that leverages our established geothermal expertise. We intend to collaborate selectively with industry-leading drilling and subsurface service providers and engage with emerging EGS and advanced geothermal technology companies to enhance execution capabilities, shorten time to market, and reduce technical and commercial risks. This approach positions us to deliver scalable, reliable geothermal solutions while maintaining capital discipline, execution certainty, and sustainable cash flow generation.

Business Goals

Our goals include continuing our leading position in the geothermal energy market and becoming a leading global provider of renewable energy. Our strategy focuses on four main elements:

• Developing our low carbon renewable geothermal business in the United States and globally;
• Growing our market position in the IFM energy storage market;
• Pursuing our core capabilities and to lead the next-generation geothermal market; and
• Pursuing synergistic and environmentally responsible growth by leveraging our core competencies, strong market reputation, and new market opportunities across the renewable energy sector.

We intend to implement this strategy through the following initiatives:

• Development and Construction of New Geothermal Power Plants — We intend to identify commercially viable geothermal resources and expand exploration drilling to accelerate development and construction of zero-emission geothermal power plants. We expect to continue entering into long-term PPAs that provide stable cash flows and support long-term value creation.
• Expanding our Geographical Reach — We plan to increase business development activities to grow our global footprint across all segments.
• Accelerating Development and Construction of New Energy Storage Assets — We intend to increase business development efforts to identify sites and advance construction of energy storage facilities, including hybrid storage and solar PV facilities. Our goal is to grow our energy storage portfolio with grid-supporting solutions that balance long-term contracted revenues (including tolling agreements) with selective merchant exposure.
• Acquisition of Geothermal Assets — We intend to accelerate growth through strategic global acquisitions, including geothermal assets and operating or development-stage assets that support our geothermal business, enhance scale, and strengthen long-term value creation.
• Acquisition of Energy Storage Projects and Solar plus Storage Assets — We intend to accelerate growth through acquisitions of operating assets, shovel-ready projects, and projects in various development stages, applying disciplined evaluation criteria for returns, risk allocation, permitting progress, and contract quality.
• Increasing Output from Existing Geothermal Power Plants — We plan to increase output from existing plants by adding generating capacity, upgrading technology, drilling new or redrilling existing wells, and improving reservoir management, including heat source supply and delivery methods.
• Diversifying Our Customer Base — At our Electricity segment we plan to evaluate strategies to expand our customer base, including in-front-of-the-meter opportunities with hyperscalers, data centers developers and operators, corporations, and CCA markets. In the near term, we expect the majority of Electricity Segment revenues to continue coming from traditional utility customers.
• Maintaining a Prudent and Flexible Capital Structure — We seek to maintain a prudent, flexible capital structure supported by multiple financing sources, including non-recourse and recourse project financings, bonds (including green bonds), corporate bank debt, sales of differential membership interests and equity interests in subsidiaries, tax credit transfers, revolving credit facilities and term loans. Our cash flow profile, long-term contracts, and capital-raising ability provide flexibility to optimize our capital structure over time.
• Improving Our Technological Capabilities — We intend to continue investing in renewable energy R&D, leveraging our expertise to improve power plant components, reduce O&M costs, develop competitive low-carbon generation products, and pursue new service opportunities. We are expanding our geothermal competencies to provide high-efficiency solutions for high-enthalpy applications using our binary enhanced cycle technology.
• Manufacturing and Providing Products and EPC Services — We intend to continue designing, manufacturing and contracting power plants for our own use and selling power units and other generation equipment for geothermal and recovered energy-based electricity generation.
• Expanding into Next-Generation Geothermal (Including EGS) — We are working to leverage our core geothermal expertise to develop and deploy next-generation geothermal solutions across both our Product and Electricity segments, including EGS. This includes advancing internal R&D, and building on existing pilot initiatives, including our collaboration with SLB and Sage, while selectively developing capabilities internally or with third parties to address technical gaps and unlock new market opportunities aligned with our strategic plan.
• Expanding into New Technologies Across Renewable Energy Platforms— We intend to leverage our technological capabilities across multiple renewable energy platforms, including, solar power generation and

energy storage. We aim to support continuous innovation through research and development efforts designed to enhance efficiency, reliability, and long-term performance.

The map below shows our worldwide portfolio of operating geothermal, solar PV and recovered energy power plants as of February 25, 2026.

*In Indonesia, in the Sarulla complex and in Ijen power plant we include our 12.75% and 49% share only, respectively.

The map below shows our portfolio of operating storage facilities as of February 25, 2026.

Sustainability Strategy

We are committed to engaging with stakeholders on sustainability matters and to continue strengthening our sustainability practices. We participate in and support external initiatives and collaborate with national and international associations that we believe promote alignment with our sustainability priorities, particularly with respect to geothermal energy, health and safety, and human rights. We also seek to provide timely, credible and comparable information to sustainability rating agencies and to engage with institutional investors and investor advocacy organizations on sustainability-related matters.

As a provider of renewable energy solutions, we monitor climate-related risks and opportunities and pursue initiatives to reduce our GHG emissions and improve energy efficiency across our operations. In addition to complying with applicable regulatory requirements, we report our annual GHG emissions to organizations such as the Carbon Disclosure Project and the Israeli Ministry of Environmental Protection’s voluntary business reporting initiative.

We report annually on our progress toward environmental goals and commitments in our sustainability reports, including measures related to climate change mitigation, biodiversity conservation and water management. Our most recent Sustainability Report is available, free of charge, on our website at https://www.ormat.com/en/sustainability/report/documents/. The contents of our website, including our sustainability reports, are not part of, and are not incorporated by reference into, this Form 10-K.

Our Proprietary Technology

Our proprietary technology involves original designs of Organic Rankine Cycles including equipment such as turbines, pumps, and heat exchangers, as well as formulation of organic motive fluids (all of which are non-ozone-depleting substances). Such equipment can be used either in power plants operating according to the ORC alone or in combination with various other commonly used thermodynamic technologies that convert heat to mechanical power, such as gas and steam turbines. It can be used with a variety of thermal energy sources, such as geothermal, recovered energy, biomass, solar energy and fossil fuels.

We also developed, patented and constructed GCCU power plants in which the steam first produces power in a backpressure steam turbine and is subsequently condensed in a vaporizer of a binary plant, which produces additional power. Our Geothermal Combined Cycle technology, that we have deployed in previous years, is depicted in the diagram below.

In the conversion of geothermal energy into electricity, our technology has several advantages over conventional geothermal steam turbine plants. A conventional geothermal steam turbine plant consumes significant quantities of water, causing depletion of the aquifer and requiring cooling water treatment with chemicals and consequently a need for the disposal of such chemicals. A conventional geothermal steam turbine plant also creates a visual impact in the form of an emitted plume from the cooling towers, especially during cold weather. By contrast, our binary and combined cycle geothermal power plants have a low profile with minimal visual impact and do not emit a plume when they use air-cooled condensers. Our binary and combined cycle geothermal power plants reinject all of the geothermal fluids utilized in the respective processes into the geothermal reservoir. Consequently, such processes generally have minimal emissions.

Other advantages of our technology include simplicity of operation and maintenance and higher yearly availability. For instance, the OEC employs a low speed and high efficiency organic vapor turbine directly coupled to the generator, eliminating the need for reduction gear. In addition, with our binary design, there is no contact between the turbine blades and the geothermal fluids, which can often be very erosive and corrosive. Instead, the geothermal fluids pass through heat exchangers, which are less susceptible to erosion and can adapt much better to corrosive fluids. In addition, with the organic vapor condensed above atmospheric pressure, no vacuum system is required.

We use the same elements of our technology in our recovered energy products. The heat source may be exhaust gases from a Brayton cycle gas turbine, low-pressure steam, or medium temperature liquid found in the process industries such as oil refining and cement manufacturing. In most cases, we attach an additional heat exchanger in which we circulate thermal oil or water to transfer the heat into the OEC’s own vaporizer in order to provide greater operational flexibility and control. Once this stage of each recovery is completed, the rest of the operation is identical to that of the OECs used in our geothermal power plants and enjoys the same advantages of using the ORC. In addition, our technology allows for better load following than conventional steam turbines, requires no water treatment (since it is air-cooled and organic fluid motivated), and does not require the continuous presence of a licensed steam boiler operator on site.

Our REG technology is depicted in the diagram below.

Patents

As of December 31, 2025, we had 182 active patents and patent applications worldwide, including 52 patents issued in the U.S. and 12 pending patent applications worldwide. These patents and patent applications cover our products (mainly power units based on the ORC) and systems (mainly geothermal power plants and industrial waste heat recovery plants for electricity production). The product-related patents cover components that include turbines, pumps, heat exchangers, air coolers, seals and controls as well as geothermal production well pumps. The system-related patents cover not only particular components but also the overall energy conversion system from the “fuel supply” (e.g., geothermal fluid, waste heat, biomass or solar) to electricity production.

The system-related patents also cover subjects such as waste heat recovery related to gas pipeline compressors and industrial waste heat, solar power systems, disposal of non-condensable gases present in geothermal fluids, reinjection of other geothermal fluids ensuring geothermal resource sustainability, power plants for very high-pressure geothermal resources, two-phase fluids, low temperature geothermal brine as well as processes related to EGS. The remaining terms of our issued patents range from one year to 16 years. The loss of any single patent would not have a material effect on our business or results of operations.

Research and Development

We conduct research and development activities intended to improve plant performance, reduce costs, and increase the breadth of our product offerings. The primary focus of our research and development efforts is targeting power plant conceptual thermodynamic cycle and major equipment including continued performance, cost and land usage improvements to our condensing equipment, and development of new higher efficiency and higher power output turbines and brine production pumps.

As part of our continuous cost reduction and performance enhancement, we developed and patented the extraction ORC, extraction and injection turbines that allow bleed or injection of motive fluid between stages from or to the organic turbine. As the ACC is a significant piece of equipment involved in the ORC process, we focus our efforts on improving ACC performance and reduce its cost, such as the wind guiding vanes for wind effects mitigation, inclined ACC and tubes geometry variation.

We also devote resources to research and development for our Energy Storage segment. Our engineering and R&D teams are working to optimize the dispatch strategy of a BESS, develop and deploy capabilities to self-integrate BESS and test different battery cell and inverter technologies under simulated operating criteria of various energy markets to allow us to bring to market cost-effective BESS more rapidly and more optimized to the specific use cases and target revenue streams. Additionally, we hold patents in other energy storage solutions, including a mechanical energy storage system, which is currently under design and feasibility examination. A preliminary trial of this system in a small-scale unit was performed, and testing remains ongoing. Initial results obtained high RTE values compared to other mechanical energy storage solutions.

We continue to evaluate investment opportunities in companies with innovative technology or product offerings for renewable energy and energy storage solutions.

Ormat New Ventures

Ormat New Ventures is the Company’s strategic corporate venture capital platform. It was established to support Ormat’s long-term growth strategy by investing in early-stage energy and climate technology companies whose innovations may complement the Company’s core businesses and contribute to future development opportunities.

The investment strategy focuses primarily on hardware- and systems-based technologies that can be integrated into operating energy infrastructure or enable the development of new projects. Areas of interest include advanced geothermal technologies, energy storage solutions, renewable and waste heat recovery technologies (including industrial-scale heat pumps, heat engines and other clean power generation solutions), and nuclear fission small modular reactor (“SMR”) deployment technologies.

As a strategic investor, Ormat New Ventures seeks to provide portfolio companies with access to the Company’s technical expertise, project development capabilities and operational experience, in addition to capital. This approach is intended to support the advancement of technologies toward commercial deployment while enabling the Company to evaluate potential applications that may enhance future projects and operating assets or being key to new markets.

Ormat New Ventures maintains an evergreen investment structure, providing flexibility in the timing and size of investments based on strategic alignment and potential impact.

As of the date of this Annual Report, the portfolio includes investments in the following companies:

• Sage Geosystems – Geo-pressurized geothermal technology designed for power generation, long-duration energy storage or district heating from low-permeability formations.
• LAVA – Isothermal thermodynamic cycle technology for heat-to-power conversion applications.
• TerraWave – Millimeter-wave drilling technology intended to enable access to deep and super hot geothermal resources.
• RepAir Carbon – Electrochemical carbon capture technology for industrial low concentration and direct air capture applications.
• Novocycle – Lithium-ion battery recycling technology focused on pre-treatment stage innovation to achieve higher content of material recovery.

Market Opportunities

Geothermal Market Opportunities

Renewable energy provides a long-term solution to multiple global energy challenges, including climate change, grid reliability concerns, and exposure to volatile fossil fuel commodity prices. As a result, many countries are prioritizing the development of clean, decarbonized, and dispatchable baseload renewable generation, with increasing interest in geothermal energy.

At the end of 2025, the total installed geothermal power generation capacity stood at 17,144 MW, an increase of 271 MW in 2025. The United States, Indonesia, the Philippines, Turkey, Kenya and New Zealand are the leading countries in geothermal power generation.

Governments around the world have recognized the need to diversify energy supply and reduce greenhouse gas emissions. In response, many jurisdictions have adopted, or are in the process of adopting, regulatory frameworks and policy mechanisms intended to support the deployment of low-carbon generation resources and achieve emissions reduction targets.

United States

Federal

Interest in geothermal energy in the United States continues to grow, supported by legislative and regulatory activity at the local, state, and federal levels. Policymakers and regulators increasingly recognize the ability of geothermal generation to provide reliable, non-intermittent renewable power and support grid reliability objectives. In January 2025, President Trump issued multiple Executive Orders focused on energy policy, including declaring a national energy emergency and seeking to increase domestic energy production, including geothermal energy.

At the federal level, the BLM recently adopted a new categorical exclusion for geothermal resource confirmation activities on federal geothermal leases, which is expected to reduce permitting burdens and facilitate development on public lands. In addition, the current federal administration declared an energy emergency in 2025, allowing for alternative NEPA procedures to be implemented to process energy development applications on federal lands. Both permitting authorities were utilized by BLM in 2025 for geothermal projects, expediting permitting timelines for resource confirmation activities and certain development projects. Federal approvals for administrative permits, including geothermal drilling permits, are also being processed in a timely manner, which may support increased drilling activity on federal lands.

On July 4, 2025, the OBBBA was enacted into law in the United States, replacing the IRA. The law seeks to limit content from foreign entities of concern (“FEOC”) used in energy related projects that start construction after December 31, 2025. For more information, see Note 16 in the consolidated financial statements contained in this annual report.

Other Drivers of Renewable Energy Demand in the U.S.

Demand for renewable energy in the United States continues to be supported by several structural trends, including expected growth in electricity consumption from data centers, corporate decarbonization objectives, and increased electrification across multiple end-use sectors. Data centers are significant energy consumers, and as companies strive to cut emissions and boost sustainability, they are securing renewable energy through PPAs to meet carbon-free targets. In addition, broader electrification trends in transportation and industrial processes may increase overall electricity demand and support the need for additional renewable generation resources.

Increased PPA Prices in the U.S.

Increased demand for renewable power, direct demand from hyper-scalers and constrained availability of firm, dispatchable generation in certain markets have contributed to higher PPA prices. The gap between electricity supply and demand in parts of the U.S. has driven higher energy and capacity pricing. Ormat has signed several PPAs for new capacity and for existing capacity renewal across its U.S. geothermal fleet at prices above $100 per MWh, compared to PPAs executed at levels generally between $60 per MWh and $80 per MWh during the prior five years.

State legislation and Incentives

Geothermal power is currently generated in several U.S. states, including California, Nevada, Hawaii, Idaho, Oregon, and Utah. Ormat believes there are opportunities to expand geothermal development in additional western states, including New Mexico and Colorado. New Mexico recently passed legislation increasing renewable energy requirements for investor-owned utilities to 100% by 2045, and Colorado’s Energy and Carbon Management Commission recently adopted streamlined geothermal permitting regulations.

Many states have implemented a RPS programs requiring utilities to incorporate renewable energy into their generation portfolios over defined compliance periods. Renewable energy generation under these programs is typically tracked through RECs, which are used by load-serving entities to demonstrate compliance with applicable RPS requirements.

Currently, 30 states plus the District of Colombia and two U.S. territories have enacted an RPS, renewable portfolio goals, or similar laws or incentives (including clean energy standards or goals) requiring or encouraging load-serving entities to procure a specified percentage of electricity from renewable energy or recovered heat sources. Additionally, three states and one territory have voluntary renewable energy goals. A significant portion of Ormat’s geothermal projects are located in California, Nevada, and Hawaii, which have among the most stringent RPS programs in the country. Ormat sees the impact of RPS and climate legislation as a significant driver to expanding existing power plants and building new renewable projects.

Certain states also offer incentives supporting geothermal energy development. For example, Nevada provides a property tax abatement of up to 55% for qualifying property used to generate geothermal electricity potentially for up to twenty years if certain job creation requirements are met. Colorado added new incentive programs beginning in 2024, including grant programs and investment and production tax credits and added additional programs in 2025 intended to continue incentivizing development of long-lead-time resources. Idaho, exempts geothermal energy producers from property tax and instead impose a 3% tax on gross energy earnings. California provides grants and loans through the California Energy Commission to promote the development of geothermal resources and technologies. In addition, the CPUC has required load-serving entities to procure significant amounts of new clean electricity, including procurement requirements for firm and dispatchable resources with high capacity factors and low on-site emissions. With its high capacity factor and ability to provide firm and flexible generation, geothermal energy may support compliance with these requirements and serve as a replacement for certain retiring baseload generation resources.

Global

We believe the global markets continue to present growth and expansion opportunities in both established and emerging markets.

We believe several global climate-related initiatives are likely to create business expansion opportunities for us and support the global growth of the renewable sector. Although in January 2025 President Trump signed an Executive Order to withdraw the United States from the Paris Agreement, it was initially adopted by the Twenty-first Conference of the Parties to the United Nations (UN) Framework Convention on Climate Change (2015) and subsequent UN Climate Change Conferences have reaffirmed the commitments of the Paris Agreement.

Outside of the U.S., the majority of power-generating capacity has historically been owned and controlled by governments. Since the early 1990s, however, many foreign governments have privatized their power generation industries through sales to third parties encouraging new capacity development and/or refurbishment of existing assets by independent power developers.

Latin America

Several Latin American countries have renewable energy programs and have pursued development in the geothermal market.

In Guatemala, where our Zunil and Amatitlan power plants are located, the Guatemalan government’s Energy Policy 2013-2027 aims for 80% renewable energy by 2027 to ensure competitive electricity prices. Recent years have shown spot prices rising over 20% annually. With no major new generation investments expected, high prices may persist until at least 2032-2034. Despite recent volatility, market conditions are expected to stabilize later in the year.

In Honduras, where we operate our Platanares power plant, the government set a target to reach at least 80% renewable energy production by 2034. State utility ENEE is seeking up to 1,500 MW of firm capacity through large tenders.

In New Zealand, where we have been actively providing geothermal power plant solutions since 1988, the government’s policies to fight climate change include a net zero GHG emissions reduction target by 2050 and a renewable electricity generation target of 90% of New Zealand’s total electricity generation by 2035. We continue selling power plants and products to our New Zealand customers and cooperate with other potential customers for adding geothermal power generation capacity within the coming years. In 2023, we signed an EPC contract to build the Ngatamariki 58MW geothermal power plant following the 59MW Tehuka 3 geothermal project contract signed in 2022. In 2024 we signed an EPC contract to build the Te-Mihi 2A 101MW geothermal power plant, and in 2025 we built the 58MW Ngatamariki and the 50MW TOPP2 plants. The 59 MW Te Huka Unit 3 geothermal power plant achieved commercial operation in June 2025 and the 50MW TOPP 2 achieved commercial operation in January 2026.

Asia

Indonesia has an estimated geothermal potential of 23GW, the largest in the world, but has only utilized about 2.7 GW (i.e. 13%) of this potential. The Government of Indonesia has made a Nationally Determined Contribution to reduce GHG emissions by 43.2% and achieve net zero emissions by 2060. To meet this target, the Indonesian government has planned to increase the use of renewable energy, with geothermal energy planned to increase by 5.2GW by 2034. To further accelerate the development of renewable energy, Presidential Regulation No. 112 was enacted in 2022, which outlines renewable energy investment incentives and sets more favorable electricity tariffs for renewable energy.

In early 2025, we commenced commercial operation of the 35MW Ijen Power Plant, a joint development with Medco Power Indonesia, which started operation in February 2025. We are making intensive efforts to expand our power plant portfolio in Indonesia. Throughout 2024 and 2025, Ormat won four tenders of fields with the potential of 122MW in total to expand our exploration field portfolio in Indonesia for up to 182MW of geothermal capacity.

In the Product segment, we see increasing market demand for our binary technology. With the successful COD of the 15MW Salak binary power plant in early February 2025 which uses the Ormat system and is the first full single phase binary power plant in Indonesia, we plan to continue to develop and capture the binary market in Indonesia with geothermal and REG power plants.

Plans to build binary power plants have been announced by multiple geothermal companies. As outlined in PLN’s Electricity Supply Business Plan for 2025-2034, a binary market totaling 500MW is expected to be ready for development by 2030, offering opportunities for our Product segment.

Since 2004, we have established strong business relationships in the Turkish geothermal market and provided our wide range of solutions, including our binary systems, to over 40 geothermal power plants with a total capacity of over 900MW and 96 MW under construction. The 15-year FIT in place and the recent 2026 Turkish Economic Coordination Council addressing issues relating to geothermal energy are cultivating development of new projects and investments which have been at a standstill due to the ongoing economic crises in Turkey.

East Africa

In East Africa the geothermal potential along the Rift Valley is estimated at several thousand MW. The countries along the Rift Valley are at different stages of development of their respective geothermal potential.

In Kenya, there are already several geothermal power plants, including our 150MW Olkaria III complex. The Kenyan government has identified the country's untapped geothermal potential as the most suitable indigenous source of electricity.

According to the Kenya National Energy Compact 2025–2030, the Government of Kenya aims to increase renewable power generation capacity to approximately 5.95 GW by 2030, including about 1.68 GW of geothermal capacity, representing roughly 28% of the targeted renewable generation mix, with the objective of transitioning the national grid from approximately 83% to 100% clean energy sources.

Energy Storage

Energy storage systems utilize surplus available electricity that enables utilities and grid operators to optimize the operation of the grid, run generators closer to full capacity for longer periods, and operate the grid more efficiently and effectively. As penetration of wind and solar resources increases, so does the need for services that energy storage systems can provide to “balance the grid”, such as local capacity, frequency regulation, ramping, reactive power, and movement of energy from times of excess supply to times of high demand. Common applications for energy storage systems include ancillary services, wind/solar smoothing, energy trading, gas peaker replacement, and transmission and distribution deferral.

In general, the energy storage market is impacted by battery prices that are linked to lithium prices and tariffs affecting China. 2025 was a volatile year for BESS pricing due to the implementation of tariffs and tariff policy changes, as well as the increase in demand due to the enactment of the OBBBA. OBBBA introduced foreign entity of concern (FEOC) requirements for projects starting construction after December 31, 2025, which led to developers (including Ormat) safe harboring prior to the end of 2025 so that ITC can be maintained. For more information, see Part I of this Annual Report, Item 1A “Risk Factors—Risks Related to the Company’s Business and Operation—We could be impacted by regulatory and other responses to climate change” and “—Risks Related to Governmental Regulations, Laws and Taxation—The reduction, elimination or inability to monetize government incentives could adversely affect our business, financial condition, future results and cash flows”. FEOC restrictions will need to be navigated by all developers moving forward to qualify for ITC benefits. Various battery suppliers are preparing to manufacture batteries in the U.S., which is expected to result in additional tax benefits for projects that will use domestically produced batteries.

According to Wood Mackenzie's Energy Storage Monitor, the U.S. energy storage market added 5,268MW/ 14,465MWh across all segments in Q3 2025. Texas and California were responsible for 82% of the installed capacity. Most of these additions, 4,588MW/13,591MWh, were grid-scale storage facilities which our Energy Storage segment focuses on. This segment’s installation capacity increased by 27% over Q3 2024. Wood Mackenzie is forecasting that 93 GW of energy storage will be added to the grid between 2025-2029, with the majority expected to be grid-scale installations.

We currently own and operate 17 grid-scale BESS facilities and two hybrid solar PV and BESS facilities, where revenues are derived from selling energy, capacity and/or ancillary services in merchant markets like PJM, ISO-NE, ERCOT, CAISO and Hawaii. We are pursuing the development of additional grid-connected BESS projects in multiple regions, with expected revenues coming from providing energy, capacity and/or ancillary services on a merchant basis, or through long-term contracts with load serving entities, e.g., investor-owned utilities, publicly owned utilities and community choice aggregators. We are also pursuing the development and construction of additional hybrid solar PV and BESS facilities. We believe that interconnection remains the key bottleneck for storage development in the U.S., and a primary driver of project timelines.

Growing grid volatility and the expected acceleration of intermittent generation, driven in part by increasing data center electricity demand, are materially expanding the need for energy storage solutions. These market dynamics have supported the development of new tolling structures in Texas and strengthened tolling pricing in California. By entering into tolling agreements, Ormat enhances the proportion of fixed, contracted revenues within the segment, improving cash flow visibility, strengthening earnings stability, and reducing exposure to merchant power price volatility

We have been awarded two separate 15-year tolling agreements for two Energy Storage facilities in Israel under the tolling agreements that are expected to have a combined capacity of approximately 300MW/1200MWh. The ownership of the projects will be shared, 50/50 between Ormat and Allied Infrastructure LTD, a leading infrastructure company in Israel.

Solar PV

Although there is a renewed focus on fossil fuel energy sources by the new presidential administration, the solar PV market continues to grow and benefits from state renewable portfolio targets as well as the general desire to replace fossil fuel generation with renewable resources. We are monitoring market drivers with the potential to develop solar PV power plants in locations where we can offer competitively priced power generation. We currently operate 60MW of standalone solar PV generation and recently commissioned a 42MW solar PV plus 35MW/140MWh BESS project in the Imperial Valley in California and acquired 30MW solar PV plus a 30MW/120MWh BESS project in Hawaii. We also have a pipeline of hybrid PV and BESS development projects in various western states, targeting future utility procurement.

In addition, Ormat continues to focus on adding solar PV systems to some of our operating geothermal power plants to reduce internal consumption loads. Since 2019, we successfully placed in service 48MW of solar PV augmentation systems and acquired an additional 20MW of solar PV augmentations adjacent to operating geothermal power plants in Nevada and are currently developing an additional 36MW.

Operations of our Electricity Segment

How We Explore and Evaluate Geothermal Resources

We conduct exploration activities globally. It generally takes two to five years from the time we start active exploration of a particular geothermal resource to the time we have resource confirmation through drilling and testing. This timeframe assumes the resource is commercially viable and there is an intention to pursue its development. Exploration activities generally involve the phases described below.

Initial Evaluation

We identify and evaluate potential geothermal resources through field investigations using a robust geoscience program identified through both public and private data sources. On average, our expenses for an initial evaluation range from approximately $10,000 (mainly in the U.S.) to $50,000 (mainly for international prospects) including travel, chemical analyses, and data acquisition.

If we conclude, based on the information considered in the initial evaluation, that the geothermal resource has potential to support a commercially viable power plant, considering various factors described below, we proceed to land rights acquisition.

Land Acquisition

We acquire land rights to any geothermal resources that our initial evaluation indicates could potentially support a commercially viable power plant. For domestic power plants, we either lease or own the sites on which our power plants are located. For our foreign power plants, our lease rights for the power plant site are generally contained in the terms of a concession agreement or other contract with the host government or an agency thereof.

For most of our current exploration sites in the U.S., we acquire rights to use the geothermal resource through land leases with the BLM (which regulates leasehold interests in U.S. federal land), with various states, or through private leases. A summary of our typical lease terms is provided below under “Description of our Leases and Lands”. The up-front bonus and royalty payments vary from site to site and are based on, among other things, current market conditions.

Surveys

We conduct geological, geochemical, and/or geophysical surveys on the sites we acquire. These surveys are conducted incrementally considering relative value and cost, and the geologic model is updated continuously.

We make a further determination of the commercial viability of the potential geothermal resource based on the results of this process, particularly the results of the geochemical surveys estimating temperature and the overall geologic model, including potential resource size. We generally only move forward with those sites that we believe have a moderate to high probability of successful development.

Exploratory Drilling & Testing

We drill exploratory wells on the high priority, relatively low risk sites to confirm and/or define a geothermal resource. Each year we determine and approve an exploration budget for the entire exploration activity in such year. We prioritize budget allocation between the various geothermal sites based on commercial, business, and portfolio management factors. The costs we incur for exploratory drilling vary from site to site based on various factors, including the accessibility of the drill site, the exploration strategy, and conceptual model of the resource. The type of exploratory drilling performed varies and can range from shallow temperature gradient wells to medium depth core drilling to full-size exploration wells. The exploration program typically focuses on the lowest cost option to de-risk the prospect such as temperature gradient wells to delineate a thermal anomaly and further de-risk targets with larger diameter wells. However, exploration costs, prior to drilling of a full-size well, are $1.0 million to $5.0 million for each site, not including land acquisition, and depending on the success we see in the early stages of exploration. Outside the U.S. exploration costs can be higher.

If we conclude that a geothermal resource will support a commercially viable power plant, we move to the phase of constructing a power plant at the site. Additional wells may be drilled during the plant construction phase to meet the design point criteria.

How We Construct Our Power Plants.

The principal phases involved in constructing one of our geothermal power plants are as follows:

• Drilling production and injection wells. The number of production and injection wells varies from plant to plant depending on, among other things, the geothermal resource, the projected capacity of the power plant, the power generation equipment to be used and the way geothermal fluids will be re-injected through injection wells to maintain the geothermal resource and surface conditions. In the last five years, our cost for each production and injection well ranged between $2.1 million to $13.0 million. An average cost for a domestic well was approximately $4.3 million and $8.0 million for international wells.
• Designing the well field, power plant, equipment, controls, and transmission facilities. The designs vary based on various factors, including local laws, required permits, the geothermal resource, the expected capacity of the

power plant and the way geothermal fluids will be re-injected to maintain the geothermal resource and surface conditions.

• Obtaining any required permits, electrical interconnection and transmission agreements. The permits and licenses required vary from site to site and are described below under “Environmental Permits”.
• Manufacturing (or in the case of equipment we do not manufacture ourselves, purchasing) the equipment required for the power plant. Generally, we manufacture most of the power generating unit equipment we use at our power plants. Multiple sources of supply are typically available for all other equipment we do not manufacture.
• Assembling and constructing the well field, power plant, transmission facilities, and related facilities. We perform site grading and civil, structural, mechanical, insulation, electrical, control, and communication works required for project execution. Construction materials (such as concrete and rebar), equipment (including cranes and forklifts), and tools are supplied as necessary to complete the work.

In general, it has taken approximately two to three years from the time we drill a production well until a power plant becomes operational. During 2025 in the Electricity segment, we focused on the commencement of operations for the repower of the upgrade of Ormesa 1 and the upgrades to our Olkaria III geothermal power plant. We also focused on construction of the Puna repower in Hawaii, Dominica geothermal power plant in the island of Dominica, Bouillante geothermal expansion in Guadeloupe, and construction of the TOPP2 geothermal power plant in New Zealand that was sold at COD to a third party. We also conducted enhancement work in some other of our operating power plants worldwide.

When deciding whether to continue holding lease rights and/or to pursue exploration activity, we diligently prioritize our prospective investments, taking into account resource and probability assessments in order to make informed decisions about whether a particular project will support commercial operation.

We may conclude that a prospective geothermal resource will not support commercial operations. In such case, costs associated with exploration activities will be expensed accordingly under the Write-off of Unsuccessful Exploration Activities line item in the consolidated statements of operations in our financial statements.

How We Operate and Maintain Our Power Plants

Our operations and maintenance practices are designed to minimize operating costs without compromising safety or environmental standards while maximizing plant flexibility and maintaining high reliability. Our operations and maintenance practices for geothermal power plants seek to preserve the sustainable characteristics of the geothermal resources we use to produce electricity and maintain steady-state operations within the constraints of those resources reflected in our relevant geologic and hydrologic studies.

Safety is a key area of concern to us. We believe that the most efficient and profitable performance of our power plants can only be accomplished within a safe working environment for our employees. Our compensation and incentive program includes safety as a factor in evaluating our employees, and we have a well-developed reporting system to track safety and environmental incidents, if any, at our power plants.

How We Sell Electricity

In the U.S., our customers are investor-owned, publicly owned utilities, and, more recently, data centers operators, Hyperscalers, public and private corporations and CCAs. Outside the U.S., our customers are typically state-owned utilities or privately owned entities. In these markets, we generally operate our facilities under rights granted by a governmental agency through a concession agreement.

In all cases, we enter into long-term contracts, typically PPAs, for the sale of electricity or the conversion of geothermal resources into electricity. Historically, revenue from our power plants under a PPA has consisted of two components: energy payments and capacity payments.

Energy payments are usually based on the actual electrical output delivered by a power plant, measured in kilowatt-hours (kWh). Payment rates may be fixed, indexed to the power purchaser’s “avoided” power costs (i.e., the costs the purchaser would have incurred if it generated the power itself), or subject to annual escalation at a predetermined rate.

Capacity payments, on the other hand, are calculated based on the generating capacity or declared capacity of a power plant available for delivery to the customer, regardless of the amount of electrical output actually produced or delivered. Additionally, as an example, one of our power plants in Hawaii is eligible for capacity payments under its PPAs when certain generation levels are met. Conversely, it may be subject to a capacity payment reduction if those levels are not met.

How We Finance Our Power Plants

We have funded our power plants with different sources of liquidity such as a non-recourse or limited recourse debt, lease financing, tax monetization transactions, internally generated cash, which includes funds from operations, as well as proceeds from loans under corporate credit facilities, bonds (including green bonds), public debt and equity offerings, senior unsecured corporate bonds, and the sale of equity interests and other securities. Our debt financing permits the development of power plants with a limited amount of equity contributions, but also increases the risk that a reduction in cashflow could adversely affect a particular power plant’s ability to meet its debt obligations. Leveraged financing also means that distributions of dividends or other distributions by our subsidiaries to us are contingent on compliance with financial and other covenants contained in the applicable finance documents.

In 2025, we entered into several corporate and project finance loans, renewed our commercial papers and expanded our revolving credit facilities to support our geothermal and storage growth. In addition, we monetized PTCs and ITCs from our Heber geothermal complex and BESS projects.

Description of Our Leases and Lands

We have domestic leases on approximately 434,430 acres of federal, state, and private land in California, Hawaii, Nevada, New Mexico, Utah, Idaho and Oregon. The approximate breakdown between federal, state and private leases and owned land is as follows:

• ~78% of the acreage under our control is leased from the U.S. government, mainly through the BLM. Roughly 3% of that acreage is currently suspended;
• ~18% is leased or subleased from private landowners and/or leaseholders; and
• ~4% is owned by Ormat.

Internationally, our land position includes approximately 5,006 acres in various countries.

BLM Geothermal Leases

Certain of our domestic project subsidiaries have entered into geothermal resource leases with the U.S. government, pursuant to which they have obtained the right to conduct their geothermal development and operations on federally-owned land. These leases are made pursuant to the Geothermal Steam Act. The lessor under such leases is the U.S. government, acting through the BLM.

BLM geothermal leases grant the geothermal lessee the right and privilege to drill for, extract, produce, remove, utilize, sell, and dispose of geothermal resources on certain lands, together with the right to build and maintain necessary improvements thereon. The actual ownership of the geothermal resources and other minerals beneath the land is retained in the federal mineral estate. The geothermal lease does not grant to the geothermal lessee the exclusive right to develop the lands, although the geothermal lessee does hold the exclusive right to develop geothermal resources within the lands. Since BLM leases do not grant to the geothermal lessee the exclusive right to use the surface of the land, BLM may grant rights to others for activities that do not unreasonably interfere with the geothermal lessee’s uses of the same land, including, off-road vehicles, and/or wind or solar energy developments.

Typical BLM leases issued to geothermal lessees before August 8, 2005 have a primary term of ten years and will renew so long as geothermal resources are being produced or utilized in commercial quantities but cannot exceed a period of forty years after the end of the primary term. If at the end of the forty-year period geothermal steam is still being produced or utilized in commercial quantities and the lands are not needed for other purposes, the geothermal lessee will have a preferential right to renew the lease for a second forty-year term, under terms and conditions as the BLM deems appropriate.

BLM leases issued after August 8, 2005 have a primary term of ten years. If the geothermal lessee does not reach commercial production within the primary term, the BLM may grant two five-year extensions. If the lessee is drilling a well for the purposes of commercial production, the lease may be extended for five years and thereafter, as long as steam is being produced and used in commercial quantities, the lease may be extended for up to thirty-five years. If, at the end of the extended 35-year term, geothermal steam is still being produced or utilized in commercial quantities and the lands are not needed for other purposes, the geothermal lessee will have a preferential right to renew the lease under terms and conditions as the BLM deems appropriate.

For BLM leases issued before August 8, 2005, the geothermal lessee is required to pay an annual rental fee (on a per acre basis), which escalates according to a schedule described therein, until production of geothermal steam in commercial quantities has commenced. After such production has commenced, the geothermal lessee is required to pay royalties (on a monthly basis) on the amount or value of (i) steam, (ii) by-products derived from production, and (iii) commercially de-mineralized water sold or utilized by the project (or reasonably susceptible to such sale or use).

For BLM leases issued after August 8, 2005, (i) a geothermal lessee who has obtained a lease through a non-competitive bidding process will pay an annual rental fee equal to $1.00 per acre for the first ten years and $5.00 per acre each year thereafter; and (ii) a geothermal lessee who has obtained a lease through a competitive process will pay a rental equal to $2.00 per acre for the first year, $3.00 per acre for the second through tenth year and $5.00 per acre each year thereafter. Rental fees paid before the first day of the year for which the rental is owed will be credited towards royalty payments for that year. For BLM leases issued, effective, or pending on August 5, 2005 or thereafter, royalty rates are fixed between 1.0%-2.5% of the gross proceeds from the sale of electricity during the first ten years of production under the lease. The royalty rate set by the BLM for geothermal resources produced for the commercial generation of electricity but not sold in an arm’s length transaction is 1.75% for the first 10 years of production and 3.5% thereafter. The royalty rate for geothermal resources sold by the geothermal lessee or an affiliate in an arm’s length transaction is 10.0% of the gross proceeds from the arm’s length sale.

The holder of a BLM geothermal lease has the ability to request in writing that the BLM suspend operations related to certain leases or an approved unit for reasons that negatively impact the operator’s ability to develop the resource. BLM reviews these requests and determines if the suspension is justified. If a suspension is approved the operator is no longer required to drill, produce geothermal resources or pay rents or royalties during the suspension and the lease term will be extended by the length of time the suspension is in effect. Leases can be unsuspended via a written request to BLM and when the suspension ends the operator resumes rental and royalty payments along with drilling and production requirements.

In the event of a default under any BLM lease, or the failure to comply with any of the provisions of the Geothermal Steam Act or regulations issued under the Geothermal Steam Act or the terms or stipulations of the lease, the BLM may, 30 days after notice of default is provided to the relevant project, (i) suspend operations until the requested action is taken, or (ii) cancel the lease.

Private Geothermal Leases

Certain of our domestic project subsidiaries have entered into geothermal resources leases with private parties, pursuant to which they have obtained the right to conduct their geothermal development and operations on privately owned land. In many cases, the lessor under these private geothermal leases owns only the geothermal resource and not the surface of the land.

Typically, the leases grant our project subsidiaries the exclusive right and privilege to drill for, produce, extract, take and remove from the leased land water, brine, steam, steam power, minerals (other than oil), salts, chemicals, gases (other than gases associated with oil), and other products produced or extracted by such project subsidiary. The project subsidiaries are also granted certain non-exclusive rights pertaining to the construction and operation of plants, structures, and facilities on the leased land. Additionally, the project subsidiaries are granted the right to dispose geothermal fluid as well as the right to re-inject into the leased land water, brine, steam, and gases in a well or wells for the purpose of maintaining or restoring pressure in the productive zones beneath the leased land or other land in the vicinity. Because the private geothermal leases do not grant to the lessee the exclusive right to use the surface of the land, the lessor reserves the right to conduct other activities on the leased land in a manner that does not unreasonably interfere with the geothermal lessee’s uses of the same land, which other activities may include agricultural use (farming or grazing), recreational use and hunting, and/or wind or solar energy developments.

The leases provide for a term consisting of a primary term in the range of five to 30 years, depending on the lease, and so long thereafter as lease products are being produced or the project subsidiary is engaged in drilling, extraction, processing, or reworking operations on the leased land.

As consideration under most of our project subsidiaries’ private leases, the project subsidiary must pay to the lessor a certain specified percentage of the value “at the well” (which is not attributable to the enhanced value of electricity generation), gross proceeds, or gross revenues of all lease products produced, saved, and sold on a monthly basis. In certain of our project subsidiaries’ private leases, royalties payable to the lessor by the project subsidiary are based on the gross revenues received by the lessee from the sale or use of the geothermal substances, either from electricity production or the value of the geothermal resource “at the well”.

In addition, pursuant to the leases, the project subsidiary typically agrees to commence drilling, extraction or processing operations on the leased land within the primary term, and to conduct such operations with reasonable diligence until lease products have been found, extracted and processed in quantities deemed “paying quantities” by the project subsidiary, or until further operations would, in such project subsidiary’s judgment, be unprofitable or impracticable. The project subsidiary has the right at any time within the primary term to terminate the lease and surrender the relevant land. If the project subsidiary has not commenced any such operations on said land (or on the unit area, if the lease has been unitized), or terminated the lease within the primary term, the project subsidiary must pay to the lessor, in order to maintain its lease position, annually in advance, a rental fee until operations are commenced on the leased land.

If the project subsidiary fails to pay any installment of royalty or rental when due and if such default continues for a period of fifteen days specified in the lease, for example, after its receipt of written notice thereof from the lessor, then at the option of the lessor, the lease will terminate as to the portion or portions thereof as to which the project subsidiary is in default. If the project subsidiary defaults in the performance of any obligations under the lease, other than a payment default, and if, for a period of 90 days after written notice is given to it by the lessor of such default, the project subsidiary fails to commence and thereafter diligently and in good faith take remedial measures to remedy such default, the lessor may terminate the lease.

We do not regard any property that we lease as material unless and until we begin construction of a power plant on the property.

Description of Our Power Plants

Domestic Operating Power Plants

The following descriptions summarize certain industry metrics for our domestic operating power plants:

Power plants in the U.S.

31

32

33

Foreign Power plants

1. Don A. Campbell has experienced cooling since mid-2016, with a 3-4°F decline in the last year, causing a reduction in its generating capacity. A temperature mitigation program is ongoing.

2. The complex is experiencing heavy curtailments by KPLC, however the capacity payments are paid on the full generating capacity.

3. We hold the Platanares assets, including the project’s wells, land, permits and a PPA, under a BOT structure for 15 years from September 26, 2017, the date the Platanares plant commenced commercial operation. A portion of the land on which the project is located is held by us through a lease from a local municipality.

4. In the second quarter of 2022, Sarulla agreed with its banks on a framework that will enable it to perform remediation works that are aimed to restore the power plants' performance. The first phase of the recovery plan included the drilling of an additional production well, which was successful, and certain modifications to surface equipment are still underway. Following the positive indications from the first phase, during the second quarter of 2024, Sarulla commenced discussions with the banks towards implementation of an additional phases and expects to commence drilling of additional 2 wells, starting in 2026, aiming for the same target zone of the successful well drilled earlier.

5. The Tungsten, Brady, Steamboat, Beowawe, North Valley and Still Water Solar PV power plants generate energy that is used for the auxiliary power of the geothermal power plants.

6. McGinness Hills Complex has experienced cooling in the last few years, with an approximately 5°F decline in the last year. Temperature mitigation program is ongoing, investigating new production and injection areas.. In addition, the complex experienced heavy curtailments during the year as a result of NV Energy T-line maintenance.

7. Ijen power plant in Indonesia commenced operation in February 2025.

8. Represents Ormat’s 49% equity share in the project

9. Amatitlan PPA is expected to expire at the end of 2027, we are currently working to extend the PPA.

Future Projects

Projects Released for Construction

We have several projects in various stages of construction, including 11 projects that we have released for construction with a total capacity of 136.5MW and one project with capacity of 10MW to 15MW that is in the early stages of construction.

These projects are expected to have a total geothermal generating capacity of between 101MW and 106MW (representing our interest) and solar PV projects with a total capacity of 36MW.

Projects under Various Stages of Development that were not Released for Construction

We also have projects under various stages of development in the U.S. that we estimate will increase the generating capacity of our geothermal and Solar PV projects by approximately 24MW. We expect to continue to explore these and other opportunities for expansion so long as they continue to meet our business objectives and investment criteria. However, we prioritize our investments based on their readiness for continued construction and expected economics and therefore we are not planning to invest in all of such projects in 2026.

Future Prospects

We have a substantial land position that is expected to support future development and on which we have started or plan to start exploration activity.

Our current land position is comprised of various leases, concessions and private land for geothermal resources in 50 prospects across the western U.S., Latin America and Africa. In the U.S. we hold 34 prospects:

• 23 prospects in Nevada
• 5 prospects in California
• 2 prospects in Oregon
• 3 prospects in Utah
• 1 in New Mexico

Outside the U.S. we hold 16 prospects:

• 8 prospects in Indonesia
• 4 prospects Ethiopia
• 2 prospects in Guatemala
• 1 prospect in Honduras
• 1 prospect in New Zealand

Competition

Electricity Segment

Ormat's Electricity Segment competes with geothermal developers during the early stages of project development. At this stage, the company must either acquire resource rights or purchase a site. If Ormat is unsuccessful in securing the lease, the acquiring entity may still become a customer of Ormat’s Product Segment.

Our primary competitors are smaller, pure-play developers focused on resource identification and development. In the U.S., industry newcomers are emerging, targeting advanced subsurface geothermal systems and competing for geothermal leases using innovative drilling techniques and technologies. Internationally, competitors gain expertise from projects in their home regions. In Indonesia, Ormat faces competition from companies such as Kaishan, PT Pertamina Geothermal Energy, PT Star Energy, and, in a recent tender, Chevron (in partnership with Pertamina). Although Impex remains active in Japan's geothermal sector, Ormat has yet to encounter direct competition from Impex. Meanwhile, Turkish developers are increasingly focusing on international market expansion. Ormat also competes with other smaller pure-play geothermal developers and local providers.

In the U.S., higher electricity demand has led to rising PPA pricing and reduced scarcity in acquiring new PPAs. As a geothermal company, Ormat prioritizes markets where its vertical integration offers a competitive advantage, enabling it to develop cost-effective baseload projects.

In addition, recently, a group of venture-backed companies is entering the geothermal industry, primarily focused on enhanced geothermal systems and other next-generation technologies recently started to enter. These companies are leveraging advances in horizontal drilling, subsurface imaging, reservoir stimulation, and closed-loop or hybrid geothermal concepts, often adapted from oil and gas applications. While many of these entrants remain in the pilot or early or advanced commercial stages, they are actively competing for geothermal leases, talent, and public and private funding in the United

States and other markets. As these technologies mature and are deployed at commercial scale, such companies could become competitors to Ormat in the development of future geothermal projects, particularly in regions without conventional hydrothermal resources.

In our Product segment, we face competition from power plant equipment manufacturers and system integrators as well as engineering or project management companies.

Our competitors among power plant equipment suppliers are divided by technology, steam turbines and binary power plant manufacturers. Our main steam turbine competitors are industrial steam turbine manufacturers such as Mitsubishi Heavy Industries, Fuji Electric Co., Ltd. and Toshiba Corporation of Japan, GE/Nuovo Pignone and Ansaldo Energia of Italy.

Our binary technology competitors are manufacturers using the ORC technology. These include Mitsubishi Heavy Industries through Turboden, TICA, a Chinese air conditioning company that acquired Italian Exergy, Egesim, a Turkish electrical contractor who is collaborating with Atlas Copco mainly in the Turkish market, Baker Hughes, one of the world’s largest oilfield services and energy technology companies, which provides comprehensive subsurface-to-surface solutions. Internationally, other competitors are Kaishan, a Chinese compressor manufacturer that also develops its own projects and Fuji Electric Co., Ltd of Japan.

While we believe that we have a distinct competitive advantage based on our accumulated experience, an increase in competition, which we are currently experiencing, has started to affect our ability to secure new purchase orders from potential customers. The increased competition led to a reduction in the operating margins, which in turn impacted our profitability.

In the case of proposed EPC projects we also compete with other service suppliers, such as project/engineering companies or EPC contractors.

Energy Storage Segment

In the Energy Storage segment, we face significant competition from companies that have already established businesses in the sector, companies that are seeking to acquire established businesses to gain a foothold in the sector, and new market entrants.

The energy storage space is comprised of a multitude of companies with different business strategies, such as project developers, independent power producers, system integrators, EPC contractors, component suppliers (e.g. batteries, inverters, control software, and balance of plant), and scheduling coordinators, among others.

We continue to develop greenfield projects with great emphasis on the quality of the location and other characteristics that will make for highly profitable projects as well as targeting strategic acquisitions of development assets. Additionally, we believe that our participation and expertise in various parts of the value chain, such as engineering, procurement, construction, project development, operation and maintenance, and asset management and market participation, together with our long-term experience in commercial operations gives us a competitive advantage in the market of utility scale energy storage.

Customers

All of our revenues from the sale of electricity in the year ended December 31, 2025 were derived from fully-contracted energy and/or capacity payments under long-term PPAs with governmental, public or private utility entities. The percentage of total revenues above 5% is detailed in the table below:

Based on publicly available information, as of December 31, 2025, the credit ratings of our rated electric utility customers are as set forth below:

The credit ratings of any power purchaser may change from time to time. There is no publicly available information with respect to the credit rating or stability of the power purchasers under the PPAs for our foreign power plants other than EDF (France).

Our revenues from the Product segment are derived from contractors, owners, or operators of power plants, process companies, and pipelines.

Our revenues from the Energy Storage segment are derived from selling energy, capacity services under long term capacity contracts and/or ancillary services in merchant markets like PJM, ISO New England, ERCOT and CAISO or under long-term tolling agreement that secure fixed revenues. In addition, we are pursuing projects that will serve entities, such as investor-owned utilities, publicly owned utilities and community choice aggregators.

Human Capital Resources

Our Team

As of December 31, 2025, we employed 1,648 professionals across our global operations with the following breakdown by country: 531 in Israel, 797 in the U.S., and 320 in other countries along with 70 temporary and contracted team members.

Workforce Health and Safety

The health and safety of our employees, subcontractors, the public, and the environment is our overarching priority. We proactively identify, assess and manage risks in the facilities and offices that we own and operate. Our goal is to report, analyze, learn and improve performance to reduce the number of safety incidents.

Competitive Compensation and Benefits

We are committed to providing competitive and comprehensive benefits. Our offerings include market-aligned compensation, comprehensive healthcare coverage, short- and long-term disability benefits, and paid maternity and paternity leave. We provide retirement and pension plans in all eligible countries, including 401(k) options in the U.S. In addition, we sponsor professional development and learning opportunities to foster career growth. These benefits help us attract and retain top talent—driving innovation and long-term success.

Employee Investment

We are committed to empowering our employees through education, development, and training. Our programs include technical and soft skills training offered in-person and online, as well as leadership development programs.

Collective Bargaining Agreements & Employee Unions

As of December 31, 2025, the only employees currently represented by a labor union are the employees of our Bouillante power plant located in Guadeloupe and our battery and maintenance employees in Philadelphia. The employees in Guadeloupe are represented by the Confédération Générale du Travail de Guadeloupe and those in Philadelphia by the IBEW Local 777.

We do not maintain collective bargaining agreements for our Israeli employees. However, certain provisions of a sector-wide agreement between the Histadrut (General Federation of Labor in Israel) and the Coordination Bureau of Economic Organizations may apply to some non-managerial employees in finance, administration, and sales and marketing roles. These provisions primarily address cost-of-living adjustments, workday length, minimum wages, workplace accident insurance, vacation and sick leave, severance pay, pension contributions, and other employment conditions.

We currently provide benefits and working conditions that meet or exceed these standards. To date, we have not experienced any labor disputes, strikes, or work stoppages, and we remain committed to fostering a positive and collaborative work environment for all employees.

Insurance

We maintain partial physical damage and business interruption insurance, including the perils of flood, volcanic eruption, earthquake and windstorm, cyber coverage, general and excess liability, pollution legal liability, control of well, drilling rigs, construction risks, as well as customary worker’s compensation and automobile, marine transportation insurance, charterers’ liability and such other commercially available insurance as is generally carried by companies engaged in similar businesses and owning similar properties in the same general areas as us. Such insurance covering our properties extends to Ormat and/or our owned, controlled, direct or indirect affiliated or associated companies, subsidiary companies or corporations in amounts generally based upon the estimated replacement value and maximum foreseeable loss of our facilities (provided that certain perils including earthquake, volcanic eruption and flood coverage are subject to sublimit and/or annual aggregate limits depending on the type and location of the facility) and business interruption insurance coverage in an amount that also varies from location to location but limited to 12 months of operation.

We purchase, when and where available, certain insurance policies to cover a portion or all of our book equity investment to specified political risks involved in operating in developing countries. We hold a global political risk insurance program covering the significant political risks at certain of our locations. This program is issued by the global insurers in the private sector. Such insurance policies generally cover, subject to the limitations and restrictions contained therein, losses derived from a specified governmental act, such as expropriation, political violence, and the inability to convert local currency into hard currency and, in certain cases, the breach of agreements with governmental entities, in approximately 70% of our book net equity investment.

Regulation of the Electric Utility Industry in the U.S.

The following is a summary overview of the electric utility industry and applicable federal and state regulations and should not be considered a full statement of the law or all issues pertaining thereto.

PURPA

PURPA and FERC's regulations thereunder exempt owners of certain Qualifying Facilities, including small power production facilities that use geothermal resources as their primary energy source, from regulation under the PUHCA 2005, from many provisions of the FPA and from state laws relating to the financial, organization and rate regulation of electric utilities.

PURPA provides the owners of power plants certain benefits described below if a power plant is a “Qualifying Facility.” A small power production facility is a Qualifying Facility if: (i) the facility does not exceed 80 MW; (ii) the primary energy source of the facility is biomass, waste, geothermal, or renewable resources, or any combination thereof, and at least 75% of the total energy input of the facility is from these sources, and fossil fuel input is limited to specified uses; and (iii) the facility, if larger than one megawatt, has filed with FERC a notice of self-certification of qualifying status, or has been certified as a Qualifying Facility by FERC. The 80 MW size limitation, however, does not apply to a facility if (i) it produces electric energy solely by the use, as a primary energy input, of solar, wind, waste or geothermal resources; and (ii) an application for certification or a notice of self-certification of qualifying status of the facility was submitted not later than December 31, 1994, and construction of the facility commenced not later than December 31, 1999.

With respect to the FPA, FERC's regulations under PURPA do not exempt from the rate provisions of the FPA sales of energy or capacity from Qualifying Facilities larger than 20 MW in size that are made (a) pursuant to a contract executed after March 17, 2006 or (b) not pursuant to a state regulatory authority’s implementation of PURPA. The practical effect of these regulations is to require owners of Qualifying Facilities that are larger than 20 MW in size to obtain market-based rate authority from FERC if they seek to sell energy or capacity other than pursuant to a contract executed on or before March 17, 2006 or pursuant to a state regulatory authority’s implementation of PURPA. A sale to a public utility under PURPA at state approved avoided cost rates is generally exempt from FERC rate regulation.

In addition, provided that the purchasing electric utility has not been relieved from its mandatory purchase obligation, PURPA and FERC’s regulations obligate electric utilities to purchase energy and capacity from Qualifying Facilities at either the electric utility’s avoided cost or a negotiated rate. FERC's regulations under PURPA allow FERC, upon request of a utility, to terminate a utility’s obligation to purchase energy from Qualifying Facilities upon a finding that Qualifying Facilities have nondiscriminatory access to: (i) independently administered, auction-based day ahead, and real time markets for electric energy and wholesale markets for long-term sales of capacity and electric energy; (ii) transmission and interconnection services provided by a FERC-approved regional transmission entity and administered under an open-access transmission tariff that affords nondiscriminatory treatment to all customers, and competitive wholesale markets that provide a meaningful opportunity to sell capacity, including long-term and short-term sales, and electric energy, including long-term, short-term, and real-time sales, to buyers other than the utility to which the Qualifying Facility is interconnected; or (iii) wholesale markets for the sale of capacity and electric energy that are at a minimum of comparable competitive quality as markets described in (i) and (ii) above. FERC regulations protect a Qualifying Facility’s rights under any contract or obligation involving purchases or sales that are entered into before FERC has determined that the contracting utility is entitled to relief from the mandatory purchase obligation. FERC has granted the request of California investor-owned utilities for a waiver of the mandatory purchase obligation for Qualifying Facilities larger than 20 MW in size. In addition, FERC subsequently amended its PURPA regulations to reduce the rebuttable presumption that small power production facilities in organized markets have nondiscriminatory access to markets from 20MW to 5MW. Therefore, the California investor-owned utilities may have a basis to further reduce their mandatory purchase obligation.

With certain limited exceptions, we expect that our power plants in the U.S will continue to meet all criteria required for Qualifying Facility status under PURPA. However, if any of our domestic power plants were to lose its Qualifying Facility status, such power plant could become subject to the full scope of the FPA and applicable state regulation. The application of the FPA and other applicable state regulation to our domestic power plants could require our operations to comply with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility.

PUHCA

Under PUHCA 2005, the books and records of a utility holding company, its affiliates, associate companies, and subsidiaries are subject to FERC and state commission review with respect to transactions that are subject to the jurisdiction of either FERC or the state commission or costs incurred by a jurisdictional utility in the same holding company system. However, if a company is a utility holding company solely with respect to Qualifying Facilities, exempt wholesale generators, or foreign utility companies, it will not be subject to review of books and records by FERC under PUHCA 2005. Qualifying Facilities or exempt wholesale generators that make only wholesale sales of electricity are not subject to state commissions’ rate regulations and, therefore, in all likelihood would not be subject to any review of their books and records by state commissions pursuant to PUHCA 2005 as long as the Qualifying Facility is not part of a holding company system that includes a utility subject to regulation in that state. Additionally, most or all of our power plants and storage projects qualify as exempt wholesale generators, exempting them from PUHCA requirements as well.

FPA

Pursuant to the FPA, FERC has exclusive jurisdiction over the rates for most wholesale sales of electricity and transmission of electricity in interstate commerce. These rates may be based on a cost-of-service approach or may be determined on a market basis through competitive bidding or negotiation. FERC can accept, reject or suspend rates. The rates can be suspended for up to five months, at which point the rates become effective subject to refund. FERC can order refunds for rates that are found to be “unjust and unreasonable” or “unduly discriminatory or preferential.”

Moreover, the loss of the Qualifying Facility status of any of our power plants might also permit the off-taker, pursuant to the terms of its PPA, to cease taking and paying for electricity from the relevant power plant and to seek refunds for past amounts paid and/or a reduction in future payments.

Additionally, FERC possesses civil penalty authority, up to approximately $1.6 million per violation of the FPA per day. FERC can also require the disgorgement of unjust profits earned in connection with such violations of the FPA and revoke the right of the power plants to make sales at market-based rates.

Under the Energy Policy Act of 2005, the FPA was supplemented to empower FERC to ensure the reliability of the bulk electric system. Such authority required that FERC assume both oversight and enforcement roles. Pursuant to its new directive, FERC certified the North American Electric Reliability Corporation as the nation’s Electric Reliability Organization (ERO) to develop and enforce mandatory reliability standards to address medium and long-term reliability concerns. Today, enforcement of the mandatory reliability standards, including the protection of critical energy infrastructure, is a substantial function of the ERO and of FERC, which may impose penalties of up to approximately $1.6 million a day for violating mandatory reliability standards. We examine our projects’ compliance with NERC standards on an ongoing basis and begin work on the process of NERC registration as new projects approach the threshold at which NERC standards become applicable.

Thus, if any of the power plants were to lose Qualifying Facility status, the application of the FPA and other applicable state regulations to such power plants could require compliance with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility. Even if a power plant does not lose Qualifying Facility status, the owner of a Qualifying Facility/power plant in excess of 20 MW will become subject to rate regulation under the FPA for sales of energy or capacity pursuant to a contract executed after March 17, 2006 or not pursuant to a state regulatory authority’s implementation of PURPA. A decrease in existing rates or being ordered by FERC to pay refunds for rates found to be “unjust and unreasonable” or “unduly discriminatory or preferential” would likely result in a decrease in our future revenues.

State Regulation

Our power plants in California, Nevada, Oregon, and Idaho, by virtue of being Qualifying Facilities that make only wholesale sales of electricity, are not subject to rate, financial and organizational regulations applicable to electric utilities in those states. The power plants each sell or will sell their electrical output under PPAs to electric utilities (Sierra Pacific Power Company, Nevada Power Company, Peninsula Clean Energy, SCPPA and Idaho Power Company). All of the utilities except SCPPA are regulated by their respective state public utilities commissions. Sierra Pacific Power Company and Nevada Power Company, which merged and are doing business as NV Energy, are regulated by the PUCN. Peninsula Clean Energy is regulated by the CPUC.

Under Hawaiian law, non-fossil generators are not subject to regulation as public utilities. Hawaiian law provides that a geothermal power producer is to negotiate the rate for its output with the public utility purchaser. If such rate cannot be determined by mutual accord, the PUCH will set a just and reasonable rate. If a non-fossil generator in Hawaii is a Qualifying Facility, federal law applies to such Qualifying Facility and the utility is required to purchase the energy and capacity at its avoided cost. The rates for our power plant in Hawaii are established under a long-term PPA with HELCO.

Environmental Permits

U.S. environmental permitting regimes with respect to geothermal projects center upon several general areas of focus. The first involves land use approvals. These may take the form of Special Use Permits or Conditional Use Permits from local planning authorities or a series of operation and utilization plan approvals and right of way approvals where the geothermal facility is entirely or partly on BLM or United States Forest Service lands. Certain federal approvals require a review of environmental impacts in conformance with the federal National Environmental Policy Act. In California, some local permit approvals require a similar review of environmental impacts under a state statute known as the California Environmental Quality Act. These federal and local land use approvals typically impose conditions and restrictions on the construction, scope and operation of geothermal projects.

The second category of permitting focuses on the installation and use of the geothermal wells themselves. Geothermal projects typically have four types of wells: (i) resource confirmation wells designed to define and verify the geothermal resource, (ii) production wells to extract the hot geothermal liquids (also known as brine) for the power plant, (iii) injection wells to inject the brine back into the subsurface resource, and (iv) monitoring wells to monitor the geothermal resource. For example, on BLM lands in Nevada, California, Oregon, Utah, and Idaho, the well permits take the form of geothermal drilling permits for well installation. Approvals are also required to modify wells, including for use as production or injection wells. For all wells drilled in Nevada, a geothermal drilling permit must also be obtained from the Nevada Division of Minerals. Those wells in Nevada to be used for injection will also require Underground Injection Control (UIC) permits from the Nevada Division of Environmental Protection, Bureau of Water Pollution Control. All geothermal wells drilled in Oregon (except on tribal lands) require a geothermal well drilling permit from the Oregon Department of Geology and Mineral Industries. All geothermal wells drilled in Idaho require a well construction permit from the Idaho Department of Water Resources (IDWR) and injection wells also require UIC permitting through IDWR. Geothermal wells in Utah require permits from the Utah Division of Water Rights, and injection wells require a permit from the Utah Department of Environmental Quality. Geothermal wells on private lands in California require drilling permits from the California Department of Conservation’s Geologic Energy Management Division (CalGEM). The eventual designation of these installed wells as individual production or injection wells and the ultimate closure of any wells is also reviewed and approved by CalGEM.

The third category of permits involves the regulation of potential air emissions associated with the construction and operation of wells and power plants and surface water discharges associated with construction and operations activities. Generally, each well and plant requires a preconstruction air permit and storm water discharge permit before earthwork can commence. In addition, in some jurisdictions the wells that are to be used for production require, and those used for injection may require air emissions permits to operate. Internal combustion engines and other air pollutant emissions sources at the projects may also require air emissions permits, including managing fugitive dust emissions during construction. For our projects, these permits are typically issued at the state or county level. Permits are also required to manage storm water during project construction and to manage drilling mud from well construction, as well as to manage certain discharges to surface impoundment, if any.

The fourth category of permits, required in Nevada, California, Oregon, Utah, and Idaho, includes ministerial permits such as building permits, hazardous materials storage and management permits, and pressure vessel operating permits. We are also required to obtain water rights permits in Nevada if water cooling is being used at the power plant. In addition to permits, there are various regulatory plans and programs that are required, including risk management plans (federal and state programs) and hazardous materials management plans (in California).

In some cases, our projects may also require permits, issued by the applicable federal agencies or authorized state agencies, regarding threatened or endangered species, permits to impact wetlands or other waters and notices of construction of structures which may have an impact on airspace. Environmental laws and regulations may change in the future that may modify the time it takes to receive such permits and the associated costs of compliance.

Our Battery Energy Storage System (BESS) projects are subject to similar permitting and regulatory compliance requirements. All of our current BESS projects are located on privately owned land and may require ministerial permits from local agencies as described above or undergo a state environmental permitting process (e.g., under the California Environmental Quality Act) with the city or county as the lead permitting agency. Storage projects are also required to comply with all applicable federal, state, and local laws and regulations, and similar to geothermal projects, may require various regulatory plans and programs including emergency action plans and fire response plans.

As of the date of this report, all of the material environmental permits and approvals currently required for our operating power plants and BESS projects have been obtained. We sometimes experience regulatory delays in obtaining various environmental permits and approvals required for projects in development and construction. These delays may lead to increases in the time and cost to complete these projects. Our operations are designed and conducted to comply with applicable environmental permit and approval requirements. Non-compliance with any such requirements could result in fines and penalties and could also affect our ability to operate the affected project.

Environmental Laws and Regulations

Our facilities and operations are subject to a number of federal, state, local and foreign environmental laws and regulations relating to development, construction and operation. In the U.S, these may include the Clean Air Act, the Clean Water Act, the Emergency Planning and Community Right-to-Know Act, the Endangered Species Act, the National Environmental Policy Act, the Resource Conservation and Recovery Act, and related state laws and regulations.

Our geothermal operations involve significant quantities of brine (substantially, all of which we reinject into the subsurface) and scale, both of which can contain materials (such as arsenic, antimony, lead, and naturally occurring radioactive materials) in concentrations that exceed regulatory limits used to define hazardous waste. We also use various substances, including isopentane and industrial lubricants that could become potential contaminants and are generally flammable. As a result, our projects are subject to domestic and foreign federal, state and local statutory and regulatory requirements regarding the generation, handling, transportation, use, storage, treatment, fugitive emissions, and disposal of hazardous substances. The cost of investigation and removal or remediation activities associated with a spill or release of such materials could be significant. Hazardous materials are also used in our equipment manufacturing operations in Israel.

Although we are not aware of any mismanagement of these materials, including any mismanagement prior to the acquisition of some of our power plants that has materially impaired any of the power plant sites, any disposal or release of these materials onto the power plant sites, other than by means of permitted injection wells, or could lead to contamination of the environment and result in material cleanup requirements or other responsive obligations under applicable environmental laws.

Regulation Related to the Energy Storage Segment

Our participation in the energy storage space and in energy management requires us to obtain and maintain certain additional authorizations and approvals. These include (1) authorization from FERC to make wholesale sales of energy, capacity, and ancillary services at market-based rates, and (2) membership status with eligibility to serve designated contractual functions in the ISO/RTOs of PJM, NYISO, CAISO, ISO-NE, and ERCOT. Among other requirements, our market-based rate sellers are subject to certain market behavior and anti-market manipulation rules and, if any of our subsidiaries were deemed to have violated any one of those rules, such subsidiary could be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of market-based rate authority, as well as criminal and civil penalties. If the market-based rate authority for one (or more) of our subsidiaries was revoked or it was not able to obtain market-based rate authority when necessary, and it was required to sell energy on a cost-of-service basis, it could become subject to the full accounting, record keeping and reporting requirements of FERC. In the future, we may need to obtain and maintain similar membership and eligibility status with other ISO/RTOs in order to offer such services in their respective areas.

Regulation of the Electric Utility Industry in our Foreign Countries of Operation

The following is a summary overview of certain aspects of the electric industry in the foreign countries in which we have an operating geothermal power plant. As such, it should not be considered a full statement of the laws in such countries or all of the issues pertaining thereto.

Guatemala

The General Electricity Law of 1996, Decree 93-96, created a wholesale electricity market in Guatemala and established a new regulatory framework for the electricity sector. The law created a new regulatory commission, the CNEE, and a new Independent System Operator and wholesale power market administrator, the AMM, for the operation and administration of the sector. The AMM is a private not-for-profit entity. The CNEE functions as an independent agency under the Ministry of Energy and Mines and is in charge of regulating, supervising, and controlling compliance with the electricity law, overseeing the market and setting rates for transmission services, and distribution to medium and small customers. All distribution companies must supply electricity to such customers, and need power purchase agreements with independent power producers to cover that demand pursuant to long-term contracts with electricity generators. Large customers can contract directly with the distribution companies, electricity generators or power marketers, or buy energy in the spot market. Guatemala has approved a Law of Incentives for the Development of Renewable Energy Power plants, Decree 52-2003, in order to promote the development of renewable energy power plants in Guatemala. This law provides certain benefits to companies utilizing renewable energy, including a 10-year exemption from corporate income tax and VAT on imports and customs duties for new generation equipment. In August 2024 CNEE issued a resolution that approved the Technical Norms for the Connection, Operation, Control and Commercialization of the Renewable Distributed Generation and Self-producers Users with Exceeding Amounts of Energy. This Technical Norm was created to regulate all aspects of generation, connection, operation, control and commercialization of electric energy produced with renewable sources to promote and facilitate the installation of new generation plants, and to promote the connection of existing generation plants which have excess amounts of electric energy for commercialization, provided the capacity does not exceed 5MW. At present, the General Electricity Law and the Law of Incentives for the Development or Renewable Energy Power Plants are still in force.

Kenya

The electric power sector in Kenya is regulated by the Kenyan Energy Act. Among other things, the Kenyan Energy Act provides for the licensing of electricity power producers and public electricity suppliers or distributors. KPLC is the major licensed public electricity supplier and has a virtual monopoly in the distribution of electricity in the country with the exception of a few off-grid, which have been licensed by the EPRA. The Kenyan Energy Act permits IPPs to install power generators and sell electricity to KPLC, which is owned by various private and government entities, and which currently purchases energy and capacity from other IPPs in addition to our Olkaria III complex. The electricity sector is regulated by the EPRA under the Kenyan Energy Act. KPLC’s retail electricity rates are subject to approval by the EPRA. The EPRA has an expanded mandate to regulate not just the electric power sector but the entire energy sector in Kenya. Transmission of electricity is undertaken by KETRACO while another company, GDC, is responsible for geothermal assessment, drilling of wells and sale of steam for electricity operations to IPPs and KenGen. Both KETRACO and GDC are wholly owned by the government of Kenya. Renewable energy dominated by geothermal, wind and, presently at a lower level, solar is one of the key energy sub-sectors in Kenya contributing significantly to the overall energy mix as a result of the implementation of the feed-in tariff policy by the Ministry of Energy. The implementation of the Renewable Energy Auctions Policy by the Ministry of Energy, which was expected to replace the feed-in-tariff policy with respect to solar, wind and other renewable energy projects exceeding 20MW, has yet to be implemented. Under the national constitution enacted in August 2010, formulation of energy policy (including electricity) and energy regulation are functions of the national government. However, the constitution lists the planning and development of electricity and energy regulation as a function of the county governments (i.e. the regional or local level where an individual power plant is or is intended to be located).

Indonesia

The Electricity Law No. 32 of 2009 (in conjunction with Government Regulation In Lieu of Law No. 2 of 2022 on Job Creation*/Omnibus Law) is the principal regulation for the electricity industry in Indonesia which divides the industry into two broad categories: (1) electrical power provision, covering electric power generation, transmission, distribution and sales, and (2) electrical power support such as services (consulting, construction, installation, operation & maintenance, certification & training, testing etc.) and industry (manufacture of tools, power plant equipment, cables, electrical equipment, etc.). The Electrical power provision business is dominated by PLN (a state-owned enterprise), which is the sole owner of transmission and distribution assets and 91.6% of the power generation assets as per 2023. Private sector participation in power generation is allowed through an IPP scheme, mostly done through tenders or direct appointment for some power sources such as geothermal. Geothermal power is regulated by The Geothermal Law issued in 2014 (Law No 21 of 2014, as also amended by the Indonesian Omnibus Law in 2022), that endorses private participation as geothermal IPP. The Central government conducts tenders for geothermal fields, awarding a Geothermal Business License for the winner. Geothermal Business License holders can conduct exploration and feasibility studies within five years and subject to two extensions of one-year each, conduct well development and power plant construction and sell the electricity generated to PLN for a maximum of 30 years. Prior to the expiration of the Geothermal License, the IPP can propose to extend the license for an additional 20 years. In 2022, Presidential Regulation No. 112 was enacted with the aim of accelerating renewable energy. This regulation replaces the basis of the renewable energy tariff from the average electricity generation basic cost to a ceiling price. In this scheme, the tariff is negotiated between the IPP and PLN and must not be higher than the ceiling tariff set for a particular type of renewable energy power plant, which then is multiplied by a factor based on location.

Guadeloupe

EDF is the transmission and distribution utility in Guadeloupe and also operates a significant portion of Guadeloupe’s fossil fuel energy generation. There are also a number of IPPs in Guadeloupe, primarily producing renewable electricity. The electricity sector in Guadeloupe is regulated by the Commission Regulation of Energy (CRE), which also regulates the French electricity and gas markets in mainland France and its other overseas territories. The electricity sector in Guadeloupe is characterized by both enabling features and obstacles with respect to renewable energy. One of the most influential enabling features is a French law requiring the utility to purchase power from any interconnected renewable generator. The major obstacle preventing further uptake of renewable electricity generation is the cap on variable generation at 30% of instantaneous system load.

Honduras

In 2014, Honduras approved its new Law of Electrical Industry, which provides the legal framework for the electricity sector and replaces the previous Electricity Subsector Framework Law. The Law establishes technology-specific auctions for renewable energy. It creates the Regulatory Commission of Electric Power (CREE) as the entity in charge of supervising the bidding processes and the awarding of PPAs. CREE is also responsible for granting study permits for the construction of generation projects that use renewable natural resources. Permits will have a maximum duration of two years, and will be revoked if no studies have been initiated within a period of six months and the reports required by the CREE have not been submitted. The new law also establishes that all new capacity must be contracted through auctions and that the government can set a minimum quota for renewables in each auction. With respect to metering, after previous regulation applied legal incentives to renewable energy metering, the new law mandates utilities to buy excess power and credit it towards monthly bills and to install bi-directional meters.

Among others, the objectives of the law are to adapt the electricity sector’s legislation to the Framework Treaty for the Central American Electricity Market, which Honduras is a party to, and update the operating rules in the country’s electricity industry by incorporating structures and modern practices to increase the sector’s efficiency and competency in the production and marketing of electricity services.

With the passage of this new law, Honduras has moved into a new and open market. Under this legislation, all aspects of the market have been opened to private parties. This legislation is still being implemented within the market.

Honduras also approved a Law of Incentives for Renewable Energy Projects, Decree 70-2007, further amended by Decree 138-2013, with additional incentives such as to solar PV projects. The purpose, as in other countries of the region, is to promote the development of renewable energy power plants. Laws provide certain benefits to companies that generate power through renewable sources, including a 10-year exemption from corporate income tax and VAT on imports and customs duties, a fast-track process for certain permits and a Sovereign Guaranty by the Central Government for the payments of the off-taker, the Public Utility Company, ENEE. At present, the Law of the Electrical Industry and the Laws of Incentives for Renewable Energy Projects are still in force.

Operations of our Product Segment

Power Units for Geothermal Power Plants

We design, manufacture, and sell power units for geothermal electricity generation, which we refer to as OECs. Our customers include contractors and geothermal plant owners and operators.

The power units are usually paid for in installments, in accordance with milestones set forth in the supply agreement. We also provide the purchaser with spare parts (either upon their request or our recommendation). We provide the purchaser with at least a 12-month warranty for such products. We provide the purchaser with performance guarantees

(usually in the form of standby letters of credit), which partially terminate upon delivery of the equipment to the site and terminates in full at the end of the warranty period.

Power Units for Recovered Energy-Based Power Generation

We design, manufacture, and sell power units used to generate electricity from recovered energy or so-called “waste heat”. Our existing and target customers include interstate natural gas pipeline owners and operators, gas processing plant owners and operators, cement plant owners and operators, biomass facilities owners and operators and all other companies engaged in energy-intensive industrial processes such as glass, steel and other. We manufacture and sell the power units for recovered energy-based power generation to third parties for use in “inside-the-fence” installations or otherwise.

EPC of Power Plants

We engineer, procure and construct, as an EPC contractor, geothermal and recovered energy power plants on a turnkey basis, using power units we design and manufacture. Our customers are geothermal power plant owners as well as our target customers for the sale of our recovered-energy based power units described above. Unlike many other companies that provide EPC services, we believe that our advantage is in using our own manufactured equipment and thus have better quality and control over the quality, timing and delivery of equipment and related costs. The consideration for such services is usually paid in installments, in accordance with milestones set forth in the EPC contract and related documents. We provide performance guarantees securing our obligations under the contract.

In connection with the sale of our power units for geothermal power plants, power units for recovered energy-based power generation, we enter into agreements, from time to time, with sales representatives for the marketing and sale of such products pursuant to which we are obligated to pay commissions to such representatives upon the sale of our products in the relevant territory.

Our manufacturing operations and products are certified ISO 9001, ISO 14001, American Society of Mechanical Engineers (ASME), Pressure Equipment Directive, and TÜV, and we are an approved supplier to many electric utilities around the world.

Production pumps

Ormat delivers a full-service approach to Production Pump sales, offering not just the pump itself but the entire supporting ecosystem, including auxiliary systems, control systems, and electrical equipment. By leveraging its own inventory of pump components, Ormat provides competitive lead times and rapid delivery. Drawing on the extensive operational knowledge gained from managing over 140 pumps across its global fleet, Ormat provides expert support throughout the process, from pump definition and selection to installation supervision. Each pump is backed by a minimum 12-month warranty, reinforcing Ormat’s commitment to reliability and customer confidence. This comprehensive offering positions Ormat as a trusted partner for geothermal operators and strengthens its leadership in the renewable energy sector.

Backlog

We have a product backlog of approximately $352.0 million as of February 25, 2026, which includes revenues for the period between January 1, 2026 and February 25, 2026, compared to $340.0 million as of February 22, 2025, which included revenues for the period between January 1, 2025 and February 26, 2025. The backlog as of February 25, 2026 includes an amount of approximately $100 million related to Topp 2, which we agreed to sell in January 2026 to a third party.

The following is a breakdown of the Product segment backlog amount (in millions)by country as of February 25, 2026:

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The following is a breakdown of the Product segment backlog by technology as of February 25, 2026:

Operations of our Energy Storage Segment

Storage Projects

In addition to our Geothermal activity, we own, operate and develop energy storage projects in the U.S. at a total capacity of 415MW/1,540MWh.

Under construction and development

We have 7 projects in various stages of construction and development with a total capacity of 410.0MW, as listed in the table below.

Energy Storage Pipeline

For an energy storage prospect to move into the EPC phase, it requires site control, an executed interconnection agreement, permits from all authorities and a viable financial model. We have a substantial pipeline of approximately 2.7GW/10.0GWh of projects in different stages of development for future growth in the U.S. and Israel that we expect will help support our target to reach an energy storage portfolio of between 950-1050MW/2,500-2,900MWh by the end of 2028.

The following risk factors should be read carefully in connection with evaluating us and this Annual Report. Certain statements in “Risk Factor” are forward-looking statements. See “Cautionary Note Regarding Forward-Looking Statements” elsewhere in this Annual Report.

Risks Related to the Company’s Business and Operation

Our financial performance depends on the successful operation of our geothermal, REG and solar PV power plants under the Electricity segment, as well as our Energy Storage facilities, which are subject to various operational risks.

Our financial performance depends on the successful operation of our geothermal, REG, and solar PV power plants. In connection with such operations, we derived 70.1% of our total revenues for the year ended December 31, 2025 from the sale of electricity and 8.0% from the sale of services in the Storage segment. The cost of operation and maintenance and the operating performance of our geothermal power, REG, and solar PV power plants and our storage facilities, or of third service providers, may be adversely affected by a variety of factors, including:

• regular and unexpected maintenance and replacement expenditures;
• shutdowns due to the breakdown or failure of our equipment or third-party equipment of the transmission serving utility;
• labor disputes or collective bargaining arrangements with employees that successfully unionize;
• labor market risk;
• the presence of hazardous materials on our power plant sites;
• continued availability of cooling water supply;
• low run times of compressors at recovered energy-based plants (such as low run times of the compressor stations heating our OREG power plants, which led to power generation and the likely loss of a customer agreement at one of these plants);
• catastrophic events such as fires, explosions, earthquakes, volcanic activity, landslides, floods, releases of hazardous materials, severe weather storms or other weather events (including weather conditions associated with climate change or similar occurrences, such as the 2018 volcanic eruption that occurred in Hawaii's Big Island impacting our Puna project);
• the aging of power plants (which may reduce their availability and increase the cost of their maintenance);
• unsuccessful augmentation of batteries or other necessary equipment; and
• cyber-attacks that may interrupt the operation of our power plants.

Any of these events could significantly increase the expenses incurred by our storage facilities or our power plants, or could reduce the overall effectiveness of our storage facilities or the generating capacity of our power plants and could significantly reduce or entirely eliminate the revenues generated by one or more of our power plants, which in turn would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flows.

Our exploration, development, and operation of geothermal energy resources are subject to geological risks and uncertainties.

Our primary business involves the exploration, development, and operation of geothermal energy resources. These activities are subject to uncertainties that, in certain respects, are similar to those typically associated with oil and gas exploration, development, and exploitation, such as dry holes, uncontrolled releases, and pressure and temperature decline. Any of these uncertainties may increase our capital expenditures and our operating costs or reduce the efficiency of our power plants. We may not find geothermal resources capable of supporting a commercially viable power plant at exploration sites where we have conducted tests, acquired land rights, and drilled test wells, which would adversely affect our development of geothermal power plants and as a result would adversely affect our growth plans. Further, since the commencement of their operations, several of our power plants have experienced geothermal resource cooling, uncontrolled flow and/or reservoir pressure decline in the normal course of operations. Because geothermal reservoirs are complex geological structures, we can only estimate their geographic area and sustainable output. The viability of geothermal power plants depends on different factors directly related to the geothermal resource (such as the temperature, pressure, storage capacity, transmissivity, and recharge) as well as operational factors relating to the extraction or reinjection of geothermal fluids. Our geothermal energy power plants may also suffer an unexpected decline in the capacity of their respective geothermal wells and are exposed to a risk of geothermal reservoirs not being sufficient for sustained generation of the electrical power capacity desired over time. Recent examples include the Olkaria complex, which experienced a reduction in generation due to lower performance of the well field; the Sarulla complex, where we experienced a reduction in generation primarily due to wellfield issues at one of its power plants, as well as equipment failures which resulted in a decrease in profitability; and our Brawley power plant in California, where we recorded a non-cash impairment loss due to electricity generation lower than its generating capacity due to continuous wellfield issues. For more information on the ongoing impacts of these, see “Property, Plant and Equipment and Construction-In-Process – Impairment of Long-Lived Assets.

Another aspect of geothermal operations is the management and stabilization of subsurface impacts caused by fluid injection pressures of production and injection fluids to mitigate ground subsidence or inflation. Inflation and subsidence, if not controlled, can adversely affect farming operations and other infrastructure at or near the land surface.

Additionally, active geothermal areas, such as the areas in which our power plants are located, may be subject to frequent low-level seismic disturbances. Serious seismic disturbances, volcanic eruptions and lava flows are possible and could result in damage to our power plants (or transmission lines used by customers who buy electricity from us) or equipment or degrade the quality of our geothermal resources to such an extent that we could not perform under the PPA for the affected power plant, which in turn could reduce our net income and materially and adversely affect our business, financial condition, future results and cash flow. If we suffer a serious seismic disturbance, volcanic eruptions and lava flows, our business interruption and property damage insurance may not be adequate to cover all losses sustained as a result thereof. In addition, insurance coverage may not continue to be available in the future in amounts adequate to insure against such seismic disturbances, volcanic eruptions and lava flows.

Furthermore, absent additional geologic/hydrologic studies, any increase in power generation from our geothermal power plants, failure to reinject the geothermal fluid or improper maintenance of the hydrological balance may affect the operational duration of the geothermal resource and cause it to decline in value over time and may adversely affect our ability to generate power from the relevant power plant.

We may decide not to implement, or may not be successful in implementing, one or more elements of our multi-year strategic plan, and the plan as implemented may not achieve its goal of enhancing shareholder value through the long-term growth of our Company

There are uncertainties and risks associated with our strategic plan described in Part I of this Annual Report, Item 1, “Business—Business Goals,” including with respect to implementation and outcome. We may decide to change, or to not implement, one or more elements of the plan over time or we may not be successful in implementing one or more elements of the plan, in each case for several reasons. There is no assurance that the plan will enhance shareholder value through long-term growth of the Company to the extent currently anticipated by our management or at all. For example, we may face significant challenges and risks expanding into the energy storage market (or expanding our core geothermal business), including our ability to:

• compete with the large number of other companies pursuing similar business opportunities in energy storage and solar PV power generation, many of which already have established businesses in these areas and/or have greater financial, strategic, technological or other resources than we have;
• obtain financing on terms we consider acceptable, or at all, which we may need, for example, to develop new projects, to obtain any technology, personnel, intellectual property, or to acquire one or more existing businesses as a platform for our expansion, or to fund internal research and development, for energy storage and solar PV electric power generation products and services;
• provide energy storage services that keep pace with rapidly changing technology, customer preferences, equipment costs, increasing raw materials and transportation costs, market conditions and other factors that are unknown to us now that will impact these markets;
• manage the risks and uncertainties associated with our operating storage facilities and future development of storage and geothermal projects which may operate as facilities without long-term sales agreements, including the variability of revenues and profitability of such projects;
• devote the amount of management time and other resources required to implement this plan, while continuing to grow our core geothermal and recovered energy businesses; and
• recruit appropriate employees and labor market challenges.

Implementing the plan may also involve various costs, including, among other things: opportunity costs associated with forgone alternative uses of our resources, various expense items that will impact our current financial results, and asset revaluations (for example, businesses or other assets acquired for new energy storage or solar PV power generation products or services may suffer impairment charges, as a result of rapidly changing technology, market conditions or otherwise).

These costs may not be recovered, in whole or in part, if one or more elements of the plan are not successfully implemented. These costs, or the failure to implement successfully one or more elements of the plan, could adversely affect our reputation and could materially and adversely affect our business, financial condition, future results and cash flow.

Apart from the risks associated with implementing the plan, the plan itself will expose us to other risks and uncertainties once implemented. Expanding our customer and/or geographic base may expose us to customers with different credit profiles than our current customers or foreign countries in which we will have to learn the business and political environment.

Our investments and profitability in battery Energy Storage System (BESS) may be negatively affected by a number of factors, including increases in storage costs, expanded trade restrictions, risk of fire and volatility in merchant prices.

We devote resources to research and development related to our Energy Storage segment, and the ability of these BESS facilities to meet our performance expectations is subject to the risks inherent in newly constructed facilities, including, but not limited to, system failures, outages and design and/or construction flaws, latent defects and degradation of equipment in excess of our expectations. Battery storage facilities utilize new technologies with a relatively limited history with respect to reliability and performance. We will need to innovate in order to keep pace with industry developments and customer expectations, and there is no guarantee that such new technologies will perform as expected. If any of our battery energy storage services contains manufacturing defects or any undetected defects, errors or bugs in hardware or software, our business and financial results could be adversely affected.

The energy storage market is impacted by battery prices that are linked to lithium prices and tariffs affecting China. 2025 was a volatile year for BESS pricing as tariffs were enacted and changed as well as the increase in demand due to the enactment of the OBBBA. These tariffs, the adoption and expansion of trade restrictions, the occurrence of a trade war or other governmental action related to tariffs, trade agreements or related policies have the potential to adversely impact our supply chain and access to equipment, our costs and ability to economically serve certain markets. If additional measures are imposed or other negotiated outcomes occur, our ability or the ability of our suppliers to purchase these products on competitive terms or to access specialized technologies from other countries could be further limited, which could adversely affect our business, financial condition and results of operations.

The OBBBA also introduced FEOC requirements for projects starting construction in 2026 and beyond, which led to developers safe harboring equipment prior to the end of 2025 so that ITC can be maintained. For more information, see Part I, Item 1 “Business—Business Opportunities—United States—Federal.” The FEOC rules may have the result of leading to pressure for increased supply chain costs, reduced supply chain options, and may lead to increased priced pressure for energy products and projects. Various battery suppliers are preparing to manufacture batteries in the U.S., which is expected to result in additional tax benefits for projects that will use domestically produced batteries. The reduction, elimination or inability to monetize government incentives and/or continued volatility in the tariff, could adversely affect our business, financial condition, future results and cash flows.

The revenues from our BESS facilities fluctuate over time since a large portion of such revenues are generated in the merchant markets, where price volatility is inherent. This volatility in merchant prices may adversely effect our Energy Storage profitability. We are also experiencing intense competition in the energy storage market from independent power producers, developers, and third-party investors.

Any of these events could significantly increase the expenses incurred by our BESS facilities or could significantly reduce or entirely eliminate the revenues generated by one or more of our BESS facilities plants, which in turn would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flows.

Our investments in next-generation geothermal technologies including in EGS involve significant risks and may not achieve anticipated returns.

We have made, and may continue to make, investments in EGS, which is an emerging geothermal technology that differs materially from conventional geothermal development. EGS projects seek to create or enhance geothermal reservoirs through advanced drilling, stimulation, and reservoir management techniques. While EGS has the potential to expand the geographic and resource base for geothermal energy, the technology has not yet been widely deployed at commercial scale.

EGS projects involve substantial technical, operational, and geological uncertainties, including risks related to reservoir creation and sustainability, drilling success rates, well productivity, thermal recovery, induced seismicity, permitting, and long-term system performance. There can be no assurance that EGS projects in which we invest will achieve expected technical milestones, operate reliably, or produce energy at commercially viable levels.

In addition, EGS projects generally require significant upfront capital investment, extended development timelines, and may be dependent on continued technological advances, third-party expertise, government incentives, or regulatory support. Cost overruns, delays, or changes in regulatory frameworks could adversely affect project economics. Further, because EGS is a relatively nascent technology, there is limited operating history to validate assumptions regarding long-term performance, maintenance requirements, and decommissioning obligations.

If our EGS investments fail to progress as anticipated, experience technical or regulatory setbacks, or do not achieve commercial viability, we may be required to impair some or all of our investments, incur additional costs, or forego expected returns. Any such outcomes could have a material adverse effect on our results of operations, financial condition, and cash flows.

Concentration of customers, specific projects and regions may expose us to heightened financial exposure.

Our businesses often rely on a single customer to purchase all or a significant portion of a facility’s output. The financial performance of these facilities depends on the ability of each customer to perform its obligations under a long-term agreement between the parties. A facility’s financial results could be materially and adversely affected if any of our customers fail to fulfill its contractual obligations and we are unable to find other customers in the marketplace to purchase at the same level of profitability. We cannot assure that such performance failures by our customers will not occur, or that if they do occur, such failures will not adversely affect the cash flows or profitability of our businesses. Moreover, there can be no assurance that we will be able to enter into replacement agreements on favorable terms or at all.

While we have historically been able to collect on substantially all of our receivable balances, we have received late payments and have amounts overdue from certain of our significant customers. In the Electricity segment, we are exposed to the credit and financial condition of KPLC that buys the power generated from our Olkaria III complex in Kenya. In 2025, KPLC accounted for 11.9% of our total revenues. There has been a deterioration in the collection from KPLC that became slower than in the past, and as of December 31, 2025, the amount overdue from KPLC in Kenya was $29.5 million of which $21.1 million was paid in January and February of 2026. In addition, KPLC recently requested more favorable rates on its existing PPAs with it. Any change in KPLC’s financial condition or the terms of our agreement with KPLC, may adversely affect us.

In Honduras, as of December 31, 2025, the total amount overdue from ENEE was $20.3 million of which $1.0 million was collected in January and February of 2026. In addition, due to the financial situation in Honduras, the Company may experience additional delays in collection. The Company believes it will be able to collect all past due amounts in Honduras.

We are also exposed to the credit and financial condition of SCPPA and its municipal utility members that account for 17.8% of our total revenues in 2025, as customers that buy the output from seven of our geothermal power plants. Because our contracts with SCPPA are long-term, we may be adversely affected if the credit quality of any of these customers were to decline or if their respective financial conditions were to deteriorate or if they are otherwise unable to perform their obligations under our long-term contracts.

In addition, we generate a significant portion of our revenue from our two largest projects, the McGinness Hills complex in east Nevada and the Olkaria III Complex in Kenya, which together accounted for approximately 23.7% of the total generating capacity of our Electricity segment in 2025. These two facilities accounted for 20.7% of our total revenues for the year ended December 31, 2025. Any disruption to the operation of these facilities would have a disproportionately adverse effect on our revenues and on our profitability. In 2025, we experienced high curtailments in the McGinness Hills complex related mostly to third party grid maintenance that impacted our revenues by approximately $6.3 million.

Our international operations expose us to risks related to the application of international laws and regulations.

Our global operations in countries including Kenya, Turkey, Guadeloupe, Guatemala, Honduras, Indonesia and others require us to comply with the laws and regulations of various governments and regulatory authorities outside the U.S. in addition to legal and regulatory requirements in the U.S. Such foreign laws or regulations may not provide the same type of legal certainty, rights, or judicial processes with respect to our contractual relationships in such countries, as are afforded to our operations in the U.S. A failure to receive adequate judicial or enforcement protection of our contractual rights abroad may adversely affect our ability to fulfill our contracts successfully and generate revenues therefrom. In particular, the legal and regulatory systems in the foreign jurisdictions where we operate can be characterized by one or more of the following:

• Selective or inconsistent enforcement of laws or regulations, sometimes in ways that have been perceived as being motivated by political or financial considerations;
• A perceived lack of judicial and prosecutorial independence from political, social and commercial forces;
• A high degree of discretion on the part of the judiciary and governmental authorities;
• Legal and bureaucratic obstacles and corruption;
• Rapidly evolving legal systems may not always coincide with market developments.

We face additional risks inherent in conducting business internationally, including compliance with laws and regulations of many jurisdictions that apply to our international operations. These laws and regulations may apply to us, our subsidiaries, individual directors, officers, employees and agents, and may restrict our operations, trade practices, investment or acquisition decisions or partnership opportunities. These requirements include, but are not limited to, data privacy requirements, labor relations laws, tax laws, competition regulations, import and trade restrictions, economic sanctions, and export requirements.

In particular, our international operations are subject to U.S. and foreign anti-corruption laws and regulations, such as the Foreign Corrupt Practices Act of 1977, as amended (the “FCPA”) and other local laws that prohibit corrupt payments to governmental officials or certain payments or remunerations to customers. The FCPA prohibits U.S. companies and their officers, directors, employees and agents acting on their behalf from corruptly offering, promising, authorizing or providing anything of value to foreign officials for the purposes of influencing official decisions or obtaining or retaining business or otherwise obtaining favorable treatment. The FCPA also requires companies to make and keep books, records and accounts that accurately and fairly reflect transactions and dispositions of assets and to maintain a system of adequate internal accounting controls. As part of our business, we deal with state-owned business enterprises, the employees and representatives of which may be considered foreign officials for purposes of the FCPA. As a result, business dealings between our employees and any such foreign official could expose us to the risk of violating anti-corruption laws even if such business practices may be customary or are not otherwise prohibited between us and a private third-party. Violations of these legal requirements are punishable by criminal fines and imprisonment, civil penalties, disgorgement of profits, injunctions, debarment from government contracts as well as other remedial measures.

Given the high level of complexity of these laws, there is a risk that some provisions may be breached by us, for example through fraudulent or negligent behavior of individual employees (or third parties acting on our behalf), our failure to comply with certain formal documentation requirements, or otherwise. Violations of these laws and regulations could result in fines, criminal sanctions against us, our officers or our employees, requirements to obtain export licenses, cessation of business activities in sanctioned countries, implementation of compliance programs and prohibitions on the conduct of our business. Any such violation could include prohibitions on our ability to offer our products in one or more countries and could materially damage our reputation, our brand, our ability to attract and retain employees, our business, our financial condition and our results of operations.

Furthermore, existing laws or regulations may be amended or repealed, and new laws or regulations may be enacted or issued. In addition, the laws and regulations of some countries may limit our ability to hold a majority interest in some of the power plants that we may develop or acquire, thus limiting our ability to control the development, construction and operation of such power plants, or our ability to import our products into such countries.

Political, economic and other conditions in the emerging economies where we operate, may subject us to greater risk than in the developed U.S. economy, which may have a materially adverse effect on our business.

We have substantial operations outside of the U.S., both in our Electricity segment and our Product segment. In 2025, 40.3% of our total revenues were derived from international operations, and our Electricity segment international operations had higher gross profit than our U.S. operations. Thus, disturbances to and challenges facing our foreign operations, especially in Kenya, could have impacts on our business ranging from moderate to severe. Our foreign operations and our exposure to foreign customers that are in most cases, government owned utilities, subject us to significant political, economic and financial risks, which vary by country, and include:

• changes in government policies or personnel;
• changes in general economic conditions;
• restrictions on currency transfer or convertibility;
• the adoption or expansion of trade restrictions, such as Turkey’s ban on trade with Israel, the occurrence or escalation of a “trade war,” or other governmental action related to tariffs or trade agreements or policies among the governments of the U.S. and countries where we operate;
• reduced protection for intellectual property rights in some countries;
• changes in labor relations;
• political instability and civil unrest, and risk of war;
• terrorist acts or other similar events;
• changes in the local electricity and/or geothermal markets;
• difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations;
• breach or repudiation of important contractual undertakings by governmental entities;
• attempts by state customers of ours to renegotiate or use political leverage to renegotiate power purchase rates in existing contracts; and
• expropriation and confiscation of assets and facilities, including without adequate compensation.

Electricity Segment. In 2025, the international operations of the Electricity segment accounted for 20% of our total revenues, but accounted for 39% of our gross profit, 49% of our net income and 29% of our EBITDA. A substantial portion of Electricity segment international revenues came from Kenya (which also contributed disproportionately to our gross profit and net income) and, to a lesser extent, from Guadeloupe, Guatemala and Honduras. In Kenya, any break-up or potential privatization of KPLC, the power purchaser for our power plants located in Kenya, may adversely affect our Olkaria III complex and our overall results of operations.

Product Segment. With respect to our Product segment, 95% of our Product segment revenues in 2025 came from international sales, primarily New Zealand. Since we primarily engage in sales in those markets where there is a geothermal reservoir, any such change might adversely affect geothermal developers in those markets and, subsequently, the ability of such developers to purchase our products.

General. Outbreaks of civil and political unrest and acts of terrorism have also occurred in several countries in Africa, the Middle East and Latin America, where we have operations, such as Kenya and Honduras. Kenya experienced numerous terrorist attacks in 2014 and 2015, and has experienced an upsurge in attacks in more recent years, including in early 2019, from extremist groups. Guatemala also experienced several months of anti-government protests in 2023 and 2024. Continued or escalated civil and political unrest and acts of terrorism in the countries in which we operate could result in our curtailing operations. In the event that countries in which we operate experience civil or political unrest or acts of terrorism, especially in events where such unrest leads to an unseating of the established government, our operations in such countries could be materially impaired.

As a result of these risks, we purchase certain types of political risk insurance policies for selected countries where we operate and which are exposed to political turmoil, geopolitical issues or political uncertainty. While such policies are designed to offer assistance with respect to some political incidents that could give rise to financial liability, it does not mitigate all of the above-mentioned risks. In addition, insurance proceeds received pursuant to our political risk insurance policies, where applicable, may not be adequate to cover all losses sustained as a result of any covered risks and may at times be pledged in favor of the power plant lenders as collateral. Also, insurance may not be available in the future with the scope of coverage and in amounts of coverage adequate to insure against such risks and disturbances. Any or all of the changes discussed above could materially and adversely affect our business, financial condition, future results and cash flow.

Conditions in and around Israel, where the majority of our senior management and our main product segment production and manufacturing facilities are located, may adversely affect our operations and may limit our ability to produce and sell our products, and support our Electricity segment.

We are a multinational company and do not derive a majority of our revenues from Israel; however, the majority of our senior management and our main production and manufacturing facilities are located in Israel, approximately 26 miles from the border with the Gaza Strip, and we receive supplies for and ship products for our Product segment via the Port of Ashdod, which is also close to the Gaza Strip and its coastline. As such, political, economic and security conditions in Israel and the Middle East region directly affect our operations.

Military conflicts involving Israel, such as a re-escalation of the wars in the Middle East that lasted between 2023 and 2025, could have adverse impacts on our business. Wars could result in military reserve duty call-ups and to our ability to ship our products from Israel, which could disrupt the operations of our Product segment and potentially delay some of our growth plans in the Electricity segment. New business partners may be reluctant to do business with us, and existing partners may hesitate to renew their agreements with us, due to their uncertainty regarding our ability to perform under our commitments in Israel, and/or claim they are not obligated to perform their commitments under those agreements pursuant to force majeure. Government-imposed restrictions on movement and travel and other precautions in wartime taken to address the ongoing conflict have in the past disrupted and may in any future conflicts disrupt our management and employees’ ability to effectively perform their jobs. Moreover, the perception that we are an Israeli company could harm our business, due to the application of restrictive laws, policies, boycotts or sanctions that other countries or companies may place on Israel and companies operating there or that may otherwise limit our ability to do trade with, or secure new or existing contracts in, other countries with anti-Israel sentiment (such as Turkey or Indonesia).

Political conditions within Israel could also affect our operations or negatively impact the business environment in Israel due to the reluctance of foreign investors to invest or conduct business in Israel, increased currency fluctuations, downgrades in credit rating, increased interest rates, increased volatility in securities markets, adverse impacts on the labor market, and other related changes in macroeconomic conditions.

Some of our leases will terminate if we do not extract geothermal resources in “commercial quantities” or fail to comply with such leases or applicable law or if the lessor under any such lease defaults on any debt secured by the relevant property.

Most of our geothermal resource leases are for a fixed primary term, and then continue for so long as geothermal resources are extracted in “commercial quantities” or pursuant to other terms of extension. The land covered by some of our leases is undeveloped and has not yet produced geothermal resources in commercial quantities. Leases that cover land which remains undeveloped and does not produce, or does not continue to produce, geothermal resources in commercial quantities and leases that we allow to expire, may terminate. In the event that a lease is terminated and we determine that we will need that lease once the applicable power plant is operating, we would need to enter into one or more new leases with the owner(s) of the premises that are the subject of the terminated lease(s) in order to develop geothermal resources from, or inject geothermal resources into, such premises or secure rights to alternate geothermal resources or lands suitable for injection. We may not be able to do this or may not be able to do so without incurring increased costs, which could materially and adversely affect our business, financial condition, future results and cash flow.

Additionally, pursuant to the terms of our BLM leases, we are required to conduct our operations on BLM-leased land in a workmanlike manner and in accordance with all applicable laws and BLM directives and to take all mitigating actions required by the BLM to protect the surface of and the environment surrounding the relevant land. Certain BLM leases contain additional requirements, some of which relate to the mitigation or avoidance of disturbance of any antiquities, cultural values or threatened or endangered plant, wildlife and species. In the event of a default under any BLM lease, or the failure to comply with such requirements, or any non-compliance with any of the provisions of the Geothermal Steam Act or regulations issued thereunder, the BLM may, 30 days after notice of default is provided to our relevant project subsidiary, suspend our operations until the requested action is taken or terminate the lease, either of which could materially and adversely affect our business, financial condition, future results and cash flow.

The fee interest in the land which is the subject of some of our leases (or subleases) may currently be or may become subject to encumbrances securing loans from third-party lenders to the lessor (or sublessor). Our rights as lessee (or sublessee) under such leases (or subleases) are or may be subject and subordinate to the rights of any such lender. Accordingly, a default by the lessor (or sublessor) under any such loan could result in a foreclosure on the underlying fee interest in the property and thereby terminate our leasehold interest and result in the shutdown of the power plant located on the relevant property and/or terminate our right of access to the underlying geothermal resources required for our operations.

Our business development activities may not be successful and our projects under construction or facilities undergoing enhancement and repowering may encounter delays, which may impact our future growth.

We are routinely in the process of developing and constructing new power plants in the ordinary course of business. Our success in developing a project is contingent upon, among other things, negotiation of satisfactory engineering and construction agreements and obtaining PPAs and transmission services agreements, receipt of required governmental permits (including environmental permits), obtaining adequate financing, and the timely implementation and satisfactory completion of field development, testing and power plant construction and commissioning. We may be unsuccessful in accomplishing any of these matters or doing so on a timely basis such in cases where we have to handle legal proceedings with respect to environmental permits. Although we may attempt to minimize the financial risks attributable to the development of a project by securing a favorable PPA and applicable transmission services agreements, obtaining all required governmental permits and approvals and arranging, in certain cases, adequate financing prior to the commencement of construction, the development of a power project may require us to incur significant expenses for preliminary engineering, permitting and legal and other expenses before we can determine whether a project is feasible, economically attractive or capable of being financed.

Currently, we have geothermal projects and prospects under exploration, development or construction in the U.S., as well as in Indonesia, Guadeloupe, Guatemala, New Zealand and Dominica and we intend to pursue the development of other new plants. In addition, our current growth plans include enhancement and repowering of a number of our operating facilities, including the Zunil, Beowawe, Ijen and Puna power plants and involve replacement of old equipment and optimization of the geothermal field, including repair and enhancement of existing wells and drilling of new wells. Our completion of these facilities’ development and/or enhancement is subject to substantial risks, including:

• inability to secure a PPA;
• inability to secure transmission services agreements;
• inability to secure the required financing;
• cost increases and delays due to unanticipated shortages of adequate resources to execute the project such as equipment, material and labor;
• work stoppages resulting from force majeure events including riots, strikes and weather conditions;
• inability or delays in obtaining permits, licenses and other regulatory approvals;
• inability to satisfactorily complete field development and testing;
• failure to secure sufficient land positions for the wellfield, power plant and rights of way;
• failure by key contractors and vendors to timely and properly perform, including where we use equipment manufactured by others;
• inability to secure or delays in securing the required transmission line and/or capacity;
• adverse environmental and geological conditions (including, but not limited to, discoveries of contamination, protected plant or animal species or habitat, archaeological or cultural resources, or inclement weather conditions);
• adverse local business law;
• our attention to other projects and activities, including those in the solar energy and energy storage sectors; and
• changes in laws that mandate, incentivize or otherwise favor renewable energy sources (for more information, see “–We could be impacted by regulatory and other responses to climate change”).

Any one of these could give rise to delays, cost overruns, the termination of the plant expansion, construction or development or the loss (total or partial) of our interest in the project under development, construction, or expansion.

In addition, we enter into various types of arrangements with communities and joint venture partners, including in some cases, indigenous peoples, for the development of projects. In some circumstances, we may be required to notify, consult, or obtain the consent of certain stakeholders, such as indigenous peoples, landowners, and/or municipalities. In some jurisdictions where we have greenfield power projects, it may be possible to claim indigenous rights to land and the existence or declaration of indigenous title may affect the existing or future activities of our projects and impact our business, financial condition and results of operations. Certain of these communities and partners may have or may develop interests or objectives which are different from or even in conflict with our objectives. Any such differences could have a negative impact on the success of our projects.

We rely on power transmission facilities that we do not own or control.

We depend on transmission facilities owned and operated by others to deliver the power we sell from our power plants to our customers. If transmission is disrupted, or if the transmission capacity infrastructure is inadequate, or if there is a failure that requires long shutdown for repair, or if curtailment is required due to load system inefficiency, our ability to sell and deliver power to our customers may be adversely impacted and we may either incur additional costs or forego revenues. In addition, lack of access to new transmission capacity may affect our ability to develop new projects. In certain markets, rapid growth in renewable energy development, including solar, wind, storage and geothermal projects, has increased congestion on existing transmission systems and extended interconnection study timelines. As a result, we may experience delays in securing interconnection approvals, or limitations on available transmission capacity, which could adversely affect project development schedules, and overall project economics.

Existing congestion of transmission capacity, as well as expansion of transmission systems and competition from other developers seeking access to expanded systems, could also affect our performance.

Our use of joint ventures may limit our flexibility with jointly owned investments.

We have partners in several of our plants and we may continue in the future to develop and/or acquire and/or hold properties in joint ventures with other entities when circumstances warrant the use of these structures. These arrangements are often driven by the magnitude of capital required to complete acquisitions of generating assets, strategic partnering arrangements to access operating expertise, and other geothermal and energy industry wide trends that we presume will continue in the future. Where we hold a minority interest in a joint venture or share control or management with another party in a joint venture (such as in the case of our plant in Guadeloupe), our ability to influence joint venture operations may be limited. As such, our ownership of assets in joint ventures is subject to risks that may not be present with other methods of ownership, including:

• we could experience an impasse on certain decisions because we do not have sole decision-making authority, which could require us to expend additional resources on resolving such impasses or potential disputes, including arbitration or litigation;
• our joint venture partners could have investment goals that are not consistent with our investment objectives, including the timing, terms and strategies for any investments in the projects that are owned by the joint ventures, which could affect decisions about future capital expenditures, major operational expenditures and retirement of assets, among other things;
• our ability to transfer our interest in a joint venture to a third-party may be restricted and the market for our interest may be limited;
• our joint venture partners may be structured differently than us for tax purposes, and this could impact our ability to fully take advantage of federal tax incentives available for renewable energy projects;
• our joint venture partners might become bankrupt, fail to fund their share of required capital contributions or fail to fulfill their obligations as a joint venture partner, which may require us to infuse our own capital into the venture on behalf of the partner despite other competing uses for such capital; and
• our joint venture partners may have competing interests in our markets and investments in companies that compete directly or indirectly with us that could create conflict of interest issues.

For example, we hold a 12.75% minority interest in the Sarulla complex and, as a result, cannot control the development of its remediation plan, pace of exploration or development or major drilling decisions. Because we may, in some instances, have a reduced level of influence over our joint ventures, we may not be able to realize some or all of the benefits that we believe will be created from our involvement. If any of the foregoing were to occur, our business, financial condition and results of operations could suffer as a result.

Our operations could be adversely impacted by climate change and other extreme weather events.

We are susceptible to losses and interruptions caused by extreme weather conditions such as droughts, hurricanes, tsunamis, floods, wildfires, and water or other natural resource shortages, occurrences of which may increase in frequency and severity as a result of climate change. Climate change may also produce general changes in weather or other environmental conditions, including temperature or precipitation levels, and thus may impact consumer demand for electricity. Daily and seasonal fluctuations in temperature generally have a more significant impact on the generating capacity of geothermal energy plants than conventional power plants. Some of our power plants experience reduced generation in warm periods due to the lower heat differential between geothermal fluid and the ambient surroundings. While we generally account for the projected impact seasonal fluctuations in temperature based on our historic experience, the impact of climate change on traditional weather patterns has become more pronounced. This has reduced the certainty of our modelling efforts. For example, at the end of 2024, following wildfires in California, we experienced delays in permitting for our storage facilities as well as a reduction in demand for electricity creating overload on the grid and resulting in unexpected curtailments at some of our power plants, which in turn adversely impacted our revenues in the fourth quarter of 2024. To the extent weather conditions continue to be impacted by climate change, the generating capacity of certain of our facilities may be adversely impacted in a manner that we could not predict which may in turn adversely impact our results of operations. In addition, the potential physical effects of climate change, such as increased frequency and severity of storms, floods, and other climatic events, could disrupt our operations and cause us to incur significant costs to prepare for or respond to these effects. If we experience physical damage to our equipment and infrastructure due to climate-related natural disasters, it could lead to the suspension of our operations, additional costs to restore service and repair facilities, and delays in power generation resulting in lost revenue and potential exposure to legal claims. Such events could also impact our ability to obtain insurance coverage and we may experience rising costs of insurance coverage resulting from any damages to our assets, which could have an impact on our profitability.

Climate change could also affect the availability of a secure and economical supply of water, whether due to an increase in water restrictions, an impact on our ability to obtain water permits, or otherwise. Water is essential for the continued operation of certain of our power plants that use water cooling systems. We monitor water risk carefully. If it is determined that a water supply risk exists that could impact projected generation levels at any plant, risk mitigation efforts are identified and evaluated for implementation.

We could be impacted by regulatory and other responses to climate change and other sustainability-related matters.

As a renewable energy solution provider, we are motivated to identify our opportunities and risks with respect to climate change and take efforts to reduce our GHG emissions and improve our energy efficiency. While we generally view this as an opportunity, uncertainty regarding recent regulation or reduction in incentives in this area could also adversely affect us.

In the U.S., where we have a significant portion of our operations, the U.S. Environmental Protection Agency (the “EPA”) has adopted rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and reporting of GHG emissions from certain sources and implement standards directing the reduction of methane from certain facilities in the oil and gas sector. Similarly, various states have adopted or are considering adopting legislation and regulation focused on GHG cap-and-trade programs, carbon taxes, reporting and tracking programs and emissions limits. At the same time, no comprehensive climate change legislation has been implemented federally. Additionally, in recent years, “anti-ESG” sentiment has gained momentum, with several U.S. states and the federal government having proposed or enacted “anti-ESG” policies, legislation, or initiatives or issued related legal opinions, such as the EPA’s recent determination that it lacks the authority to regulate certain GHG emissions and would no longer stand behind its prior findings that GHG emissions are harmful. The policies of the current U.S. presidential administration also increase the prospect of regulatory ambiguity and change. For instance, while executive orders of the Trump administration from early 2025 suggest a positive posture of the administration toward geothermal energy relative to other renewable sources, the impact of these orders, in the absence of any substantive change in regulation since such orders were issued, remains unclear, and we cannot currently make any assurance about the influence of the policies or political stances of the Trump administration on our business. The BLM has also not issued new permits or renewed certain permits for certain solar technologies supporting geothermal auxiliary loads on U.S. federal lands where we have applied for permits to develop or for renewed permits to continue operating, as further described in

“Risks Related to Governmental Regulations, Laws and Taxation—The absence of new or renewed BLM permits for solar PV projects on U.S. federal lands could impair our development activities, project pipeline and growth prospects.”

Uncertainty associated with these regulations, our inability to meet the demands of these regulations or our failure to predict accurately the impact of our response to these regulations could adversely affect our business and prospects. We could also face an increase in competition due to the energy transition, as new entrants of disruptive technologies and/or competitors, including in the solar, wind, and storage sectors, could adversely impact our ability to renew existing PPAs or sign new contracts. On the other hand, anti-ESG related policies, legislation, initiatives, litigation, legal opinions, and scrutiny could result in the Company facing additional compliance obligations, becoming the subject of investigations and enforcement actions, or sustaining reputational harm. The related reduction or elimination of government incentives around renewable energy may also harm us, as described in “Risks Related to Governmental Regulations, Laws and Taxation—The reduction, elimination or inability to monetize government incentives could adversely affect our business, financial condition, future results and cash flows.”

Lastly, our sustainability disclosures, a failure to meet evolving stakeholder expectations for sustainability practices and reporting, or expenses required to carry on sustainability reporting and/or meet customer requirements or sustainability targets, may potentially harm our customer relationships and/or subject us to significant costs and liabilities and reputational risks, any of which could adversely affect our business, financial condition and results of operations.

We may not be able to successfully conclude the transactions, integrate companies, which we acquired and may acquire in the future, which could materially and adversely affect our business, financial condition, future results and cash flow.

Our strategy is to continue to expand in the future, including through acquisitions to enhance our geothermal portfolio and accelerate growth in our Electricity segment. Integrating acquisitions is often costly, and we may not be able to successfully integrate our acquired companies with our existing operations without substantial costs, delays or other adverse operational or financial consequences. Completion of M&A transactions may be subject to fulfilling conditions and receiving regulatory approval. Integrating our acquired companies involves a number of risks that could materially and adversely affect our business, including:

• failure of the acquired companies to achieve the results we expect;
• inability to retain key personnel of the acquired companies;
• risks associated with unanticipated events or liabilities; and
• the difficulty of establishing and maintaining uniform standards, controls, procedures and policies, including accounting controls and procedures.

If any of our acquired companies suffers customer dissatisfaction or performance problems, this could adversely affect the reputation of our group of companies and could materially and adversely affect our business, financial condition, future results and cash flow.

Changes in costs and technology may significantly impact our business by making our power plants and products less competitive resulting in the inability to sign new PPAs for our Electricity segment and new supply and EPC contracts for our Products segment.

A basic premise of our business model is that generating baseload power at geothermal power plants produces electricity at a competitive price. However, traditional coal-fired systems and gas-fired systems may under certain economic conditions produce electricity at lower average prices than our geothermal plants. In addition, there are other technologies that can produce electricity such as hydroelectric systems, fuel cells, microturbines, wind turbines, energy storage systems and solar PV systems. Some of these alternative technologies currently produce electricity at higher average prices than our geothermal plants while others produce electricity at lower average prices. It is possible that technological advances and economies of scale will further reduce the cost of alternate methods of power generation. It is also possible that intermittent energy technologies will compete with our basic premise of a firm (non-intermittent) renewable baseload power source by combining renewable technologies with energy storage to provide an alternative to firm baseload energy. If this were to happen, the competitive advantage of our power plants may be significantly impaired and will cause reduction and/or inability to sign new PPAs for our Electricity segment and new supply and EPC contracts for our Products segment. Competition in our Product segment has also, in general, started to our affect our ability to secure new purchase orders from potential customers. This increased competition has led to a reduction in the operating margins, in turn impacting our profitability.

Our intellectual property rights may not be adequate to protect our business.

Our existing intellectual property rights may not be adequate to protect our business. We occasionally file patent applications which cover our products (mainly power units based on the ORC) and systems (mainly geothermal power plants and industrial waste heat recovery plants for electricity production). However, the patent application process is expensive, time-consuming and complex and we may not be able to prepare, file, prosecute, maintain and enforce all necessary or desirable patent applications at a reasonable cost or in a timely manner. Patents may be invalidated and patents may not be issued on the basis of our patent applications. Additionally, the scope of patent protection can be reinterpreted after issuance. Even if our patent applications do issue as patents, they may not issue in a form that is sufficiently broad to protect our technology, prevent competitors or other third parties from competing with us or otherwise provide us with any competitive advantage. In addition, any patents issued to us or for which we have use rights may be challenged, narrowed, invalidated or circumvented. Third parties may initiate opposition, interference, re-examination, post-grant review, inter partes review, nullification or derivation actions, or similar proceedings challenging the inventorship, validity, enforceability or scope of our patents. An adverse determination in any such proceeding or litigation could reduce the scope of, or invalidate our patent rights, allow third parties to commercialize our technology and compete directly with us, without payment to us, or result in our inability to commercialize our technology without infringing third-party patent rights. Such proceedings also may result in substantial cost and require significant time from our management, even if the eventual outcome is favorable to us. Our competitors or other third parties may also be able to circumvent our patents by developing similar or alternative technologies in a non-infringing manner. Consequently, we do not know whether any of our technology will be protectable or remain protected by valid and enforceable patents.

In order to safeguard our unpatented proprietary know-how, trade secrets and technology, we rely on a combination of trade secret protection and non-disclosure provisions in agreements with employees and third parties having access to confidential or proprietary information. These measures may not adequately protect us from disclosure, use, reverse engineering, infringement, misappropriation or other violation of our proprietary information and other intellectual property rights by third parties. Furthermore, non-disclosure provisions can be difficult to enforce and, even if successfully enforced, may not be entirely effective. In addition, we cannot guarantee that we have entered into non-disclosure agreements with all employees and third parties that have or may have had access to our trade secrets and other confidential or proprietary information.

Even if we adequately protect our intellectual property rights, litigation may be necessary to enforce these rights, which could result in substantial costs to us and a substantial diversion of management attention. Furthermore, attempts to enforce our intellectual property rights against third parties could also provoke these third parties to assert their own intellectual property or other rights against us, or result in a holding that invalidates or narrows the scope of our rights, in whole or in part. Our success and ability to compete also depends in part on our ability to operate without infringing, misappropriating or otherwise violating the intellectual or proprietary rights of third parties. While we have attempted to ensure that our technology and the operation of our business does not infringe on other parties' patents and other intellectual property or proprietary rights, our competitors or other third parties may assert that certain aspects of our business or technology infringe upon, misappropriate or otherwise violate their intellectual property or proprietary rights. In addition, former employers of our current, former or future employees may assert claims that such employees have improperly disclosed to us the confidential or proprietary information of these former employers. Infringement, misappropriation or other intellectual property violation claims, regardless of merit or ultimate outcome, can be expensive, hard to predict and time-consuming and can divert management’s attention from our core business. An assertion of an intellectual property infringement, misappropriation or other violation claim against us may result in adverse judgments, settlements on unfavorable terms or cause us to pay significant money damages, lose significant revenues, be prohibited from using the relevant technology or other intellectual property, or incur significant license, royalty or technology development expenses. Future litigation may also involve non-practicing entities or other intellectual property owners who have no relevant product offerings or revenue and against whom our own intellectual property may therefore provide little or no deterrence or protection.

A cyber-incident, cyber security breach, severe natural event or physical attack on our operational networks and information technology systems could have a material adverse effect on our financial condition, results of operations, liquidity and cash flows.

We rely on information technology systems that allow us to create, store, retain, transmit and otherwise process proprietary and sensitive or confidential information, including our business and financial information, and personal information regarding our employees and third-parties. We also rely on our operational technology systems to manufacture equipment for our energy projects, operate our power plants and provide our services. In addition, we often rely on third-party vendors to host, maintain, modify and update our systems.

Our and our third-party vendors’ technology systems can be damaged by malicious events such as cyber and physical attacks, computer viruses, malicious and destructive code, phishing attacks, denial of service or information, as well as security breaches, natural disasters, fire, power loss, telecommunications failures, employee misconduct, human error, and third parties such as traditional computer hackers, persons involved with organized crime or foreign state or foreign state-supported actors. Furthermore, our disaster recovery planning may not be sufficient for all situations. Any failure, disruptions to or decrease in the functionality of our or our third-party vendors’ operational and information technology networks could impact our ability to maintain effective internal controls over financial reporting, cause harm to the environment, the public or our employees, and significantly disrupt and damage our assets and operations or those of third parties.

We and our third-party vendors have been, and may in the future be, subject to breaches and attempts to gain unauthorized access to our information technology systems or sensitive or confidential data, or to disrupt our operations. To date, none of these breaches or attempts has, individually or in the aggregate, resulted in a security incident with a material effect on our operations or our financial condition, results of operations, liquidity, or cash flows. Despite implementation of security and control measures, we and our third-party vendors have not always been able to, and there can be no assurance that we or our third-party vendors will be able to in the future, anticipate or prevent unauthorized access to our or our third-party vendors’ operational technology networks, information technology systems or data, or the disruption of our or our third-party vendors’ operations. We may be unable to anticipate techniques used to breach and may not become aware in a timely manner of such a security breach, which could exacerbate any damage we experience. Such events could cause interruptions in the operation of our business, damage our operational technology networks and information technology systems, subject us to significant expenses, remediation costs, litigation, disputes, claims by third parties and regulatory actions or investigations that could result in damages, material fines and penalties, and harm to our reputation, any of which could have a material adverse effect on our financial condition, results of operations, liquidity, and cash flows. We may maintain cyber liability insurance that covers certain damages caused by cyber incidents. However, there is no guarantee that adequate insurance will continue to be available at rates that we believe are reasonable or that the costs of responding to and recovering from a cyber-incident will be covered by insurance or recoverable in rates.

In addition, we are subject to various legislation, regulations, directives and guidelines from federal, state, local and foreign agencies, such as FERC, that are intended to strengthen cybersecurity measures required for information and operational technology and critical energy infrastructure and that apply to the collection, use, retention, protection, disclosure, transfer and other processing of personal information. In California, there are obligations on businesses to be transparent with their data privacy practices and vests consumers and employees with rights to access and delete the personal information held by businesses. These cybersecurity, data protection and privacy law regimes continue to evolve and may result in ever-increasing public scrutiny and escalating levels of capital expenditures, regulatory enforcement, sanctions and fines and increased costs for compliance. Any failure to comply with FERC or any of these legal requirements could result in enforcement action against us, including fines, imprisonment of company officials and public censure, any of which could harm our reputation and have a material adverse effect on our financial condition, results of operations, liquidity, and cash flows.

Risks Related to Governmental Regulations, Laws and Taxation

Our financial performance could be adversely affected by changes in the legal and regulatory environment affecting our operations.

All of our power plants are subject to extensive regulation, and therefore changes in applicable laws or regulations, or interpretations of those laws and regulations, could result in increased compliance costs, the need for additional capital expenditures or the reduction of certain benefits currently available to our power plants. The structure of domestic and foreign energy regulation currently is, and may continue to be, subject to challenges, modifications, the imposition of additional regulatory requirements, and restructuring proposals. We or our power purchasers may not be able to obtain all regulatory approvals that may be required in the future, or any necessary modifications to existing regulatory approvals, or maintain all required regulatory approvals. In addition, the cost of operation and maintenance and the operating performance of geothermal power plants may be adversely affected by changes in certain laws and regulations, including tax laws.

Any changes to applicable laws and regulations or interpretations of those laws and regulations could significantly increase the regulatory-related compliance, tax and other expenses incurred by the power plants and could significantly reduce or entirely eliminate the revenues generated by one or more of the power plants, which in turn would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flow. For more information, see “Risks Related to the Company’s Business and Operation—We could be impacted by regulatory and other responses to climate change and sustainability-related initiatives.”

Pursuant to the terms of some of our PPAs with investor-owned electric utilities and publicly-owned electric utilities in states that have renewable portfolio standards, the failure to supply the contracted capacity and energy thereunder may result in the imposition of penalties.

Pursuant to the terms of certain of our PPAs, we may be required to make payments to the relevant power purchaser under certain conditions, such as shortfall in delivery of renewable energy and energy credits, and not meeting certain performance threshold requirements, as defined in the relevant PPA. The amount of payment required is dependent upon the level of shortfall in delivery or performance requirements and is recorded in the period the shortfall occurs. In addition, if we do not meet certain minimum performance requirements, the capacity of the relevant power plant may be permanently reduced. Any or all of these considerations could materially and adversely affect our business, financial condition, future results and cash flow.

If any of our domestic power plants loses its current Qualifying Facility status under PURPA, or if amendments to PURPA are enacted that substantially reduce the benefits currently afforded to Qualifying Facilities, our domestic operations could be adversely affected.

Most of our domestic power plants are Qualifying Facilities pursuant to PURPA, which largely exempts the power plants from the FPA, and certain state and local laws and regulations regarding rates and financial and organizational requirements for electric utilities.

If any of our domestic power plants were to lose its Qualifying Facility status, such power plant could become subject to the full scope of the FPA and applicable state regulation. The application of the FPA and other applicable state regulation to our domestic power plants could require our operations to comply with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility.

If a domestic power plant were to lose its Qualifying Facility status, it would become subject to full regulation as a public utility under the FPA, and the rates charged by such power plant pursuant to its PPAs may be subject to the review and approval of FERC. FERC, upon such review, may determine that the rates currently set forth in such PPAs are not appropriate and may set rates that are lower than the rates currently charged. In addition, FERC may require that the affected domestic power plant refund amounts previously paid by the relevant power purchaser to such power plant. Even if a power plant does not lose its Qualifying Facility status, pursuant to regulations issued by FERC for Qualifying Facility power plants above 20MW, if a power plant’s PPA is terminated or otherwise expires, and the subsequent sales are not made pursuant to a state’s implementation of PURPA, that power plant will become subject to FERC’s ratemaking jurisdiction under the FPA. Moreover, a loss of Qualifying Facility status also could permit the power purchaser, pursuant to the terms of the particular PPA, to cease taking and paying for electricity from the relevant power plant or, consistent with FERC precedent, to seek refunds of past amounts paid. This could cause the loss of some or all of our revenues payable pursuant to the related PPAs, result in significant liability for refunds of past amounts paid, or otherwise impair the value of our power plants. If a power purchaser were to cease taking and paying for electricity or seek to obtain refunds of past amounts paid, there can be no assurance that the costs incurred in connection with the power plant could be recovered through sales to other purchasers or that we would have sufficient funds to make such payments. In addition, the loss of Qualifying Facility status would be an event of default under the financing arrangements currently in place for some of our power plants, which would enable the lenders to exercise their remedies and enforce the liens on the relevant power plant.

Pursuant to the Energy Policy Act of 2005, FERC also has the authority to prospectively lift the mandatory obligation of a utility under PURPA to offer to purchase the electricity from a Qualifying Facility if the utility operates in a workably competitive market. Our existing PPAs between a QF and a utility are not affected. If, in addition to the California utilities’ waiver of the mandatory purchase obligation for QF projects that exceed 20MW described in the risk factor above, the utilities in the other regions in which our domestic power plants operate were to be relieved of the mandatory purchase obligation, they would not be required to purchase energy from the power plant in the region under Federal law upon termination of the existing PPA or with respect to new power plants, which could materially and adversely affect our business, financial condition, future results and cash flow. Moreover, FERC has the authority to modify its regulations relating to the utility’s mandatory purchase obligation under PURPA, which could result in the reduction in the purchase obligation of California and other utilities to a level below 5MW, or the elimination of the purchase obligation. If that were to occur it could materially and adversely affect our business, financial condition, future results and cash flow.

The PURPA and QF described risks identified above are not likely to affect our Nevada based facilities that entered into PPAs with NV Energy as the off-taker after Nevada initially adopted its RPS in 2001. Those PPAs and the related rates agreed to for such facilities by the off-taker were not based upon PURPA or a QF mandated rate but were instead adopted as a result of a competitive bidding process and approved as part of the off-taker’s integrated resource planning process and in order for the off-taker to comply with Nevada’s RPS. While those PPAS were initially required to file for QF or EWG status with the FERC, the PPAs and their related prices for the term of the PPA were not approved by the FERC pursuant to PURPA. The PURPA and QF risks described above also are not likely to affect our Nevada and California based projects that have their PPAs with the SCPPA because SCPPA is not a regulated public utility under PURPA.

The absence of new or renewed BLM permits for solar PV projects on U.S. federal lands could impair our development activities, project pipeline and growth prospects.

The BLM has not issued new permits or renewed certain permits for standalone solar facilities, solar projects paired with energy storage, or solar installations intended to support geothermal auxiliary loads on U.S. federal lands where we have applied for permits to develop or for renewed permits to continue operating. While we have not recently experienced formal cancellations, the lack of new approvals and renewals creates significant regulatory uncertainty and may materially limit our ability to advance existing projects or develop new projects in locations that require federal land use permit, rights-of-way, environmental approvals, or other permits.

As a result, we may experience material delays in development timelines, increased project costs, loss of site control, termination or renegotiation of power purchase or interconnection agreements, and potential impairment of development assets. Limitations on access to U.S. federal lands may also reduce the number of viable development sites and increase competition and costs for projects on non-federal lands. Any of these factors could reduce our project pipeline, delay revenue generation, and adversely affect our growth prospects, financial condition, results of operations, and cash flows.

The reduction, elimination or inability to monetize government incentives could adversely affect our business, financial condition, future results and cash flows.

Construction and operation of our geothermal power plants, battery energy storage systems and solar PV facilities has benefited, and may benefit in the future, from public policies and government incentives that support energy production (including, in certain cases, renewable energy and enhance the economic feasibility of these projects in regions and countries where we operate. On July 4, 2025, the OBBBA was enacted into law in the United States. The OBBBA allows for geothermal to qualify for 100% PTC or ITC related to projects that start construction by the end of December 2033, 75% PTC or ITC by the end of December 2034 and 50% PTC or ITC by the end of December 2035. These incentives allow the Company to transfer credits to unrelated third parties or enter into tax equity transactions, potentially improving project economics and reducing required Company capital. We expect that the construction and operations of our geothermal power plants, battery energy storage systems and solar PV will benefit in the future from certain aspects of the OBBBA and enhance the economic feasibility of projects in the United States. For information relating to risks of the OBBBA, see Part I, Item 1 “Risk Factors—Risks Related to the Company’s Business and Operation—Our investments and profitability in Battery Energy Storage System (BESS) may be negatively affected by a number of factors, including increases in storage costs, expanded trade restrictions, risk of fire and volatility in merchant prices.”

There are additional public policy and government incentives that currently benefit and that we expect will benefit the Company in the future in countries outside of the U.S. as well as States within the U.S. The incentives in these jurisdictions include accelerated depreciation tax benefits, rebates, mandated feed-in tariffs and other similar incentives.

The availability and continuation of these public policies and government incentives have a significant effect on the economics and viability of our development program and continued construction of new geothermal, recovered energy-based, solar PV facilities and, recently, energy storage projects. Changes to such public policies, or any reduction in or elimination or expiration of such government incentives, could affect us in different ways. For example, any reduction in, termination or expiration of renewable portfolio standards may result in less demand for generation from our geothermal and recovered energy-based power plants. Any reductions in, termination or expiration of other government incentives could reduce the economic viability of, and cause us to reduce, the construction of new geothermal, recovered energy-based, solar PV or any other power plants. Policies supporting or deregulating the exploration, production and use of fossil fuels may create regulatory uncertainty in the renewable energy industry.

Similarly, any such changes that affect the geothermal energy industry differently from other renewable energy sources, such as wind or solar, may put us at a competitive disadvantage compared to businesses engaged in the development, construction and operation of renewable power projects using such other resources. In addition, although we may have the legal ability to monetize ITCs and PTCs, our ability to do so is subject to market prices and demand, which may be lower than we anticipate. Any of the foregoing outcomes could have a material adverse effect on our business, financial condition, future results, and cash flows.

Our operations are primarily conducted through our subsidiaries, which are separate legal entities, and our cash depends substantially on the performance of our subsidiaries and the power plants they operate, most of which are subject to restrictions and taxation on dividends and distributions.

Our operations are primarily conducted through our subsidiaries. We conduct no other business and, as a result, we depend entirely upon our subsidiaries’ earnings and cash flow.

The agreements pursuant to which some of our subsidiaries have incurred debt restrict the ability of these subsidiaries to pay dividends, make distributions or otherwise transfer funds to us prior to the satisfaction of other obligations, including the payment of operating expenses, debt service and replenishment or maintenance of cash reserves. In the case of some of our power plants that are owned jointly with other partners, there may be certain additional restrictions on dividend distributions pursuant to our agreements with those partners. In all of the foreign countries where our existing power plants are located, dividend payments to us may also be subject to withholding taxes. Each of the events described above may reduce or eliminate the aggregate amount of cash we can receive from our subsidiaries.

The costs of compliance with federal, state, local and foreign environmental laws and our ability to obtain and maintain environmental permits and governmental approvals required for development, construction and/or operation may result in liabilities, costs and delays in construction (as well as any fines or penalties that may be imposed upon us in the event of any non-compliance or delays with such laws or regulations) that could materially and adversely affect our business, financial condition, future results and cash flow and these liabilities and costs may increase in the future.

Our operations are subject to extensive environmental laws, ordinances and regulations, which may cause us to incur significant costs and liabilities. These laws, ordinances and regulations can be subject to change and such change could result in increased compliance costs, the need for additional capital expenditures, or otherwise adversely affect us. In addition, our power plants are required to comply with numerous federal, state, local and foreign statutory and regulatory environmental standards and to maintain numerous environmental permits and governmental approvals required for development, construction and/or operation. We may not be able to renew, maintain or obtain all environmental permits and governmental approvals required for the continued operation or further development and construction of the power plants. We have not yet obtained certain permits and government approvals required for the completion and successful operation of power plants under development, construction or enhancement. Our failure to renew, maintain or obtain required permits or governmental approvals, including the permits and approvals necessary for operating power plants under development, construction or enhancement, could cause our operations to be limited or suspended resulting in fines under the PPA. Permits and governmental approvals may also be delayed during periods of government shutdowns.

We may also be subject to litigation seeking to rescind or delay our receipt of environmental permits and governmental approvals. For example, a lawsuit was filed by the Center for Biological Diversity and the Fallon Paiute-Shoshone Tribe in 2021 that sought to revoke the BLM’s approval of the development of our Dixie Meadows geothermal power plant in Nevada, which was later closed without prejudice. There can be no assurance that the Company will be able to obtain the necessary approvals to develop Dixie Meadows as originally intended, or at all.

In addition, some of the environmental permits and governmental approvals that have been issued to the power plants contain conditions and restrictions, including restrictions or limits on emissions and discharges of pollutants and contaminants, or may have limited terms. If we fail to satisfy these conditions or comply with these restrictions, or with any statutory or regulatory environmental standards, we may become subject to regulatory enforcement action and the operation of the power plants could be adversely affected or be subject to fines, penalties or additional costs or other sanctions, including the imposition of investigatory or remedial obligations of the issuance of orders limiting or prohibiting our operations.

We could be exposed to significant liability for violations of hazardous substances laws because of the use or presence of such substances at our power plants.

Our power plants are subject to numerous domestic and foreign federal, regional, state and local statutory and regulatory standards relating to the generation, handling, transportation, use, storage, treatment and disposal of hazardous substances. We use butane, pentane, industrial lubricants, and other substances at our power plants which are or could become classified as hazardous substances. If any hazardous substances are found to have been released into the environment at or by the power plants in concentrations that exceed regulatory limits, we could become liable for the investigation and removal of those substances, regardless of their source and time of release. If we fail to comply with these laws, ordinances or regulations (or any change thereto), we could be subject to civil or criminal liability, the imposition of liens or fines, and cessation of operations, large expenditures to bring the power plants into compliance or other sanctions. Furthermore, under certain federal and states laws in the U.S., we can be held liable for the cleanup of releases of hazardous substances at any of our current or former facilities or at any other locations where we arranged for disposal of those substances, even if we did not cause the release at that location or if the release complied with applicable law at the time it occurred. Liability under these laws can be joint and several. The cost of any remediation activities in connection with a spill or other release of such substances could be significant and could expose us to significant liability.

U.S. federal, state and international income tax law changes could adversely affect us.

The Company continuously monitors and examines the impact of U.S. and international tax law changes, such as the Tax Act, CARES and similar tax law changes internationally, in order to determine the impact it may have on our business. The overall impact of the global tax law changes is uncertain, and our business, financial condition, future results and cash flow, as well as our stock price, could be adversely affected.

The Organization for Economic Co-operation and Development (OECD) has a framework to implement a global minimum corporate tax of 15% for companies with global revenues and profits above certain thresholds (referred to as Pillar 2), with certain aspects of Pillar 2 effective January 1, 2024 and other aspects effective January 1, 2025. Several countries in which the Company operates, have enacted Pillar 2. Pillar 2 rules apply to the Company beginning in the year after December 31, 2025. Based on enacted laws, Pillar 2 is not expected to materially impact the Company’s effective tax rate. New legislation or guidance could change this assessment.

Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to significant liabilities and reputational damage that could have a material adverse effect on us.

We are involved in the ordinary course of business and otherwise in a number of lawsuits involving, among other matters, employment, commercial, and environmental issues, and other claims for injuries and damages. We are also involved in the ordinary course of business in regulatory investigations and other administrative proceedings, and we are exposed to the risk that we become the subject of additional regulatory investigations or administrative proceedings. We evaluate litigation claims and legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Based on these evaluations and estimates, when required by applicable accounting rules, we establish reserves and disclose the relevant litigation claims or legal proceedings, as appropriate. These evaluations and estimates are based on the information available to management at the time and involve a significant amount of judgment. Actual outcomes or losses may differ materially from current evaluations and estimates. The settlement or resolution of such claims or proceedings may have a material adverse effect on us. We use appropriate means to contest or otherwise respond to litigation and/or regulatory proceedings threatened or filed against us, but the litigation and/or regulatory enforcement environments poses a significant business risk.

Risks Related to Economic and Financial Conditions

We may be unable to obtain the additional financing we need to pursue our growth strategy and any future financing we receive may be less favorable to us than our current financing arrangements, either of which may adversely affect our ability to expand our operations.

Some of our geothermal power plants have been financed using leveraged financing structures, consisting of non-recourse or limited recourse debt obligations. Each of our projects under development or construction and those projects and businesses we may seek to acquire, or construct will require substantial capital investment. Our continued access to capital on acceptable or favorable terms to us is necessary for the success of our growth strategy, particularly in enhancing our portfolio through M&A activities. Our attempts to obtain future financings may not be successful or on favorable terms.

In recent years, we have also increased our corporate recourse debt at the holding company level due to our ability to obtain improved economic terms, and in June 2022 we issued, $431.3 million aggregate principal amount of 2.50% convertible senior notes due 2027, and an additional $45.2 million aggregate principal amount of the same notes in July 2024. We refer to these notes collectively as the “Notes”. Our existing and any future indebtedness may make it more difficult for us to refinance or borrow additional funds in the future, limiting our ability to pursue our growth strategy.

Market conditions and other factors may not permit future project and acquisition financings on terms similar to those our subsidiaries have previously received. Our ability to arrange for financing on a substantially non-recourse or limited recourse basis, and the costs of such financing, are dependent on numerous factors, including general economic conditions, conditions in the global capital and credit markets, investor confidence, the continued success of current power plants, the credit quality of the power plants being financed, the political situation in the country where the power plant is located, and the continued existence of tax and securities laws which are conducive to raising capital. If we are not able to obtain financing for our power plants on a substantially non-recourse or limited recourse basis, we may have to finance them using recourse capital such as direct equity investments or the incurrence of additional debt by us.

Also, in the absence of favorable financing options, we may decide not to build new plants or acquire facilities from third parties. Any of these alternatives could have a material adverse effect on our growth prospects.

We may also need additional financing to implement our strategic plan. For example, our cash flow from operations and existing liquidity facilities may not be adequate to finance any acquisitions we may want to pursue or new technologies we may want to develop or acquire. Financing for acquisitions or technology development activities may not be available on the non-recourse or limited recourse basis we have historically used for our business, or on other terms we find acceptable.

Our debt obligations may adversely affect our ability to raise additional capital and will be a burden on our future cash resources, particularly if we elect to settle these obligations in cash upon conversion or upon maturity or required repurchase.

Our ability to meet our payment obligations under the Notes, depends on our future cash flow performance. This, to some extent, is subject to general economic, financial, competitive, legislative and regulatory factors, as well as other factors that may be beyond our control. There can be no assurance that our business will generate positive cash flow from operations, or that additional capital will be available to us, in an amount sufficient to enable us to meet our debt payment obligations and to fund other liquidity needs. If we are unable to generate sufficient cash flow to service our debt obligations, we may need to refinance or restructure our debt, sell assets, reduce or delay capital investments, or seek to raise additional capital. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at such time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations. As a result, we may be more vulnerable to economic downturns, less able to withstand competitive pressures and less flexible in responding to changing business and economic conditions.

Our foreign power plants and foreign manufacturing operations expose us to risks related to fluctuations in currency rates, which may reduce our profits from such power plants and operations.

Risks attributable to fluctuations in currency exchange rates can arise when any of our foreign subsidiaries incur operating or other expenses in one type of currency but receive revenues in another. In such cases, an adverse change in exchange rates can reduce such subsidiary’s ability to meet its debt service obligations, reduce the amount of cash and income we receive from such foreign subsidiary or increase such subsidiary’s overall expenses. In addition, the imposition by foreign governments of restrictions on the transfer of foreign currency abroad, restrictions on the conversion of local currency into foreign currency, or the local currency has strengthened significantly against the U.S. dollar, would have an adverse effect on the operations of our foreign power plants and foreign manufacturing operations, and may limit or diminish the amount of cash and income that we receive from such foreign power plants and operations.

If our project subsidiaries default on their obligations under such limited or non-recourse debt or lease financing, we may be required to make certain payments to the relevant debt holders, and if the collateral supporting such leveraged financing structures is foreclosed upon, we may lose certain of our power plants.

Our power plants have generally been financed using a combination of our corporate funds and limited or non-recourse project finance debt or lease financing. Limited recourse project finance debt refers to our additional agreement, as part of the financing of a power plant, to provide limited financial support for the power plant subsidiary in the form of limited guarantees, indemnities, capital contributions and agreements to pay certain debt service deficiencies. Non-recourse project finance debt or lease financing refers to financing arrangements that are repaid solely from the power plant’s revenues and are secured by the power plant’s physical assets, major contracts, cash accounts and, in many cases, our ownership interest in the project subsidiary. If our project subsidiaries default on their obligations under the relevant debt documents, creditors of a limited recourse project financing will have direct recourse to us, to the extent of our limited recourse obligations, which may require us to use distributions received by us from other power plants, as well as other sources of cash available to us, in order to satisfy such obligations. In addition, if our project subsidiaries default on their obligations under the relevant debt documents (or a default under such debt documents arises as a result of a cross-default to the debt documents of some of our other power plants) and the creditors foreclose on the relevant collateral, we may lose our ownership interest in the relevant project subsidiary or our project subsidiary owning the power plant would only retain an interest in the physical assets, if any, remaining after all debts and obligations were paid in full.

Possible fluctuations in the cost of construction, raw materials, commodities and drilling may materially and adversely affect our business, financial condition, future results, and cash flow.

Our manufacturing operations are dependent on the supply of various raw materials, including primarily steel and aluminum, commodities, vessels and industrial equipment components that we use. We currently obtain all such raw materials, commodities and equipment at prevailing market prices. We are not dependent on any one supplier and do not have any long-term agreements with any of our suppliers. Global events, such as U.S. tariffs on Canada, Mexico and China that were recently imposed or are set to take effect, and the uncertainty surrounding the possibility of expanded trade restrictions among the governments of the U.S. and countries where our suppliers operate, could result in delays in supply and increased costs. Our development activity is also impacted by the supply delay and cost increase of storage batteries and solar PV panels. Further cost increases of such raw materials, commodities and equipment could adversely affect our profit margins.

Our commodity derivative activity may limit potential gains, increase potential losses, result in earnings volatility and involve other risks.

We enter, from time to time, into commodity derivative contracts to manage our price exposure to our energy storage segment revenue. While these transactions are intended to limit our exposure to the adverse effects of fluctuations of storage services prices, they may also limit our ability to benefit from favorable changes in market conditions, and may subject us to periodic earnings volatility in the instances where we do not seek hedge accounting for these transactions or if the correlation between the hedge and the actual performance of the asset will be lower. Also, in connection with such derivative transactions, we may be required to make cash payments to maintain margin accounts and to settle the contracts at their value upon termination.

Finally, this activity exposes us to potential risk of counterparties to our derivative contracts failing to perform under the contracts. As a result, the effectiveness of our risk management could have an impact on our business, results of operations and cash flows.

We have incurred substantial indebtedness that may decrease our business flexibility, access to capital, and/or increase our borrowing costs, and we may still incur substantially more debt, which may adversely affect our operations and financial results.

As of December 31, 2025, we had $2,659.6 million outstanding aggregate principal amount of long-term debt. Our indebtedness may limit our ability to borrow additional funds for working capital, capital expenditures, acquisitions or other general business purposes, limit our ability to use our cash flow or obtain additional financing for future working capital, capital expenditures, acquisitions or other general business purposes, require us to use a substantial portion of our cash flow from operations to make debt service payments, limit our flexibility to plan for, or react to, changes in our business and industry, place us at a competitive disadvantage compared to our less leveraged competitors and increase our vulnerability to the impact of adverse economic and industry conditions.Additionally, under the Notes, if we undergo a “fundamental change,” subject to certain conditions, holders may require us to repurchase for cash all or part of their Notes at a fundamental change repurchase price equal to 100% of the principal amount of the Notes to be repurchased, plus accrued and unpaid interest, and if we undergo a “make-whole fundamental change”, the conversion rate for the Notes may be increased. These outcomes may, in certain circumstances, delay or prevent a takeover of us that might otherwise be beneficial to our stockholders.

We are exposed to various credit risks.

We rely on cross-currency swap contracts to effectively manage our currency risk related to our Senior Unsecured Bonds - Series 4 issued in July 2020. Failure of any of our counterparties to perform under derivatives contracts could disrupt our hedging operations if the counterparties do not fulfill their obligations under the agreements, particularly if we were entitled to a termination payment under the terms of the contract that we did not receive, if we had to make a termination payment upon default of the counterparty, or if we were unable to reposition the swap with a new counterparty. We are also subject to counterparty risk under the capped call transactions entered into in connection with the Notes. If an option counterparty becomes subject to insolvency proceedings, we will become an unsecured creditor with a claim equal to our exposure at the time under the capped call transactions with such option counterparty. Our exposure will depend on many factors but, generally, an increase in our exposure will be correlated to an increase in the market price and in the volatility of our common stock. A default by an option counterparty may also cause adverse tax consequences and dilution in the value our common stock.

We may not be able to obtain sufficient insurance coverage to cover damages to our assets and profitability.

We maintain physical damage and business interruption insurance. However, our business interruption and property damage insurance coverage may not be sufficient to cover all losses sustained as a result of natural disasters such as flood, volcanic eruptions, lava flows, wind and earthquake or any other insurable risk. In addition, insurance coverage may not continue to be available in the future at rates that we believe are reasonable or in amounts of coverage or with scope of coverage adequate to insure against future natural disasters. Following the May 2018 eruption of the Kilauea volcano in Hawaii, the full amount of our insurance claim for damages to our Puna power plant was denied and we experienced increased costs and difficulties in obtaining sufficient insurance coverage for natural disasters. Before the eruption in 2018, we obtained natural disasters business interruption and property damage insurance coverage of up to approximately $100 million compared to $30 million, with portions of the risk self-insured. An inability to obtain sufficient and adequate insurance to cover all book net equity may cause us to self-insure some or all of a particular location and losses, causing us to experience higher than expected insurance costs.

If insurance premiums or deductibles were to increase in the future, if certain types of insurance coverage were to become unavailable or cost prohibitive, if we were to have to increase the percentage of our self-insured insurance coverage or if we were to experience losses in excess of, or outside the scope of, our insurance coverage, such additional costs could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Risks Related to Force Majeure

The existence of a prolonged force majeure event or a forced outage affecting a power plant, or the transmission systems could reduce our net income and materially and adversely affect our business, financial condition, future results and cash flow.

The operation of our subsidiaries’ geothermal power plants is subject to a variety of risks, including public health issues, such as epidemics, pandemics, and other outbreaks, as well events such as fires, explosions, earthquakes, landslides, floods, severe storms, volcanic eruptions, lava flow or other similar events. Any of these events could result in a shutdown of certain of our businesses. If a power plant experiences an occurrence resulting in a force majeure event, although our subsidiary that owns that power plant would be excused from its obligations under the relevant PPA, the relevant power purchaser may not be required to make any capacity and/or energy payments with respect to the affected power plant for as long as the force majeure event continues and, pursuant to certain of our PPAs, will have the right to prematurely terminate the PPA. Additionally, to the extent that a forced outage has occurred, and if as a result the power plant fails to attain certain performance requirements under certain of our PPAs, the power purchaser may have the right to permanently reduce the contract capacity (and correspondingly, the amount of capacity payments due pursuant to such agreements in the future), seek refunds of certain past capacity payments, and/or prematurely terminate the PPA. As a consequence, we may not receive any net revenues from the affected power plant other than the proceeds from any business interruption insurance that applies to the force majeure event or forced outage after the relevant waiting period and may incur significant liabilities in respect of past amounts required to be refunded.

In addition to our power plant in Puna, Hawaii, our power plant in Amatitlan, Guatemala is located in proximity to an active volcano. We cannot be certain how investors will assess the risks to which our facilities are subject and whether this assessment will adversely impact perceptions of our business and our share price.

Threats of terrorism and other disasters may impact our operations in unpredictable ways and could adversely affect our business, financial condition, future results and cash flow.

Our operations and facilities, in particular, our generation and transmission facilities, information technology systems and other infrastructure facilities, systems and physical assets that we acquire, construct or develop, as well as those of third parties on which we rely, may be targets of terrorist acts and threats, as well as events occurring in response to or in connection with them, that could cause environmental repercussions, result in full or partial disruption of our operations. These operations and facilities are also subject to natural disasters, public health crises, fire, power loss and telecommunication failures. Any of our assets or those of third-party vendors could be directly or indirectly affected by such events or activities. Any such terrorist acts, environmental repercussions or disruptions or natural disasters could result in a significant decrease in revenues or significant reconstruction or remediation costs, beyond what could be recovered through insurance policies, which could have a material adverse effect on the business, financial condition, results of operations and cash flows.

Risks Related to Ownership of Our Common Stock

Future equity issuances, including through our current or any future equity compensation plans, could result in dilution, which could cause the price of our shares of common stock to decline.

We may issue additional shares of our common stock in the future pursuant to current or future equity compensation plans, upon conversions of preferred stock or debt, or in connection with future acquisitions or financings. Issuances under convertible instruments that are already outstanding, such as the Notes, may be outside of our control, and conversions to the extent allowed under these instruments may be more attractive to investors during sustained periods when our common stock price exceeds the conversion price. We may also seek to raise additional funds, finance acquisitions or develop strategic relationships by issuing additional shares of our common stock. If we choose to raise capital by selling shares of our common stock, or securities convertible into shares of our common stock, or additional shares are issued for the reasons described above or otherwise, the issuance could have a dilutive effect on the holders of our common stock and could have a material negative effect on the market price of our common stock.

The price of our common stock has in the past and may in the future fluctuate substantially, and your investment may decline in value.

The market price of our common stock has in the past and may in the future be highly volatile and may fluctuate substantially due to many factors, including:

• actual or anticipated fluctuations in our results of operations including as a result of seasonal variations in our Electricity segment-based revenues or variations from year-to-year in our Product segment-based revenues;
• variance in our financial performance from the expectations of market analysts;
• conditions and trends in the end markets we serve, and changes in the estimation of the size and growth rate of these markets;
• our ability to integrate acquisitions;
• announcements of significant contracts by us or our competitors;
• changes in our pricing policies or the pricing policies of our competitors;
• restatements of historical financial results and changes in financial forecasts;
• loss of one or more of our significant customers;
• legislation;
• changes in market valuation or earnings of our competitors;
• the trading volume of our common stock;
• under the capped call transactions we entered into in connection with the Notes, modifications by the option counterparties or their affiliates of their hedge positions which cause them to enter into or unwind derivatives in our common stock or purchase or sell our common stock or other securities;
• the trading of our common stock on multiple trading markets, which takes place in different currencies and at different times; and
• general economic conditions.

In addition, the stock market in general, and the NYSE and the market for energy companies in particular, have experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of particular companies affected. These broad market and industry factors may materially harm the market price of our common stock, regardless of our operating performance. In the past, following periods of volatility in the market price of a company’s securities, securities class-action litigation has often been instituted against that company. Such litigation, if instituted against us could result in substantial costs and a diversion of management’s attention and resources, which could materially harm our business, financial condition, future results and cash flow. We are generally obliged under our bylaws, to the extent permitted under Delaware law, to indemnify our current and former officers who are named as defendants in these types of lawsuits. While a certain amount of insurance coverage is available for expenses or losses associated with these lawsuits, this coverage may not be sufficient for certain litigation. For information on our recently dismissed and ongoing securities class actions, see “Commitments and Contingencies” in Note 20 to the consolidated financial statements contained in Item 8 of this Annual Report.

Risk management and strategy

We prioritize the management of cybersecurity risk and the protection of information across our enterprise by embedding data protection and cybersecurity risk management in our operations. Our processes for assessing, identifying, and managing material risks from cybersecurity threats have been integrated into our overall risk management system and processes.

As a foundation of this approach, our privacy and security policies govern our business lines and subsidiaries. We monitor the privacy and security regulations applicable to us in the regions where we do business as well as proposed privacy and security regulations and emerging risks.

We conduct internal and external penetration testing and risk assessments on a regular basis, and have engaged consultants, auditors and other relevant third parties to assist us with cybersecurity risk management processes. Our operations rely on the secure processing, storage and transmission of confidential and other information in our computer systems and networks. Computer viruses, hackers, and employee or vendor misconduct, and other external hazards could expose our data systems and those of our vendors to security breaches, cybersecurity incidents or other disruptions, any of which could materially and adversely affect our ability to conduct our business. While we have experienced cybersecurity incidents, to date, we are not aware that we have experienced a material cybersecurity incident. The sophistication of cybersecurity threats continues to increase, and the controls and preventative actions we take to reduce the risk of cybersecurity incidents and protect our systems, including the regular testing of our cybersecurity incident response plan, may be insufficient. In addition, new technology that could result in greater operational efficiency may further expose our computer systems to the risk of cybersecurity incidents. We may also maintain cyber liability insurance that covers certain damages caused by cybersecurity incidents. However, there is no guarantee that adequate insurance will continue to be available at rates that we believe are reasonable or that the costs of responding to and recovering from a cybersecurity incident will be covered by insurance or recoverable in rates.

For more information, see Part I of this Annual Report, Item 1A “Risk Factors—Risks Related to the Company’s Business and Operation—A cyber-incident, cyber security breach, severe natural event or physical attack on our operational networks and information technology systems could have a material adverse effect on our financial condition, results of operations, liquidity and cash flows.”

Governance

As part of our overall risk management approach, we prioritize the management of cybersecurity risk at several levels, including Board oversight, executive commitment and employee training. Our Audit Committee, comprised fully of independent directors from our Board, oversees the Board’s responsibilities relating to cybersecurity risks. Each of our Audit Committee and Board is informed of such risks through reports from our Chief Information Officer (“CIO”) at least twice per year.

Our Chief Information Security Officer (“CISO”), who has been a chief information security officer at Ormat for eight years, is certified by the International Information System Security Certification Consortium as an Information Systems Security Management Professional (“ISSMP”), as an Information Systems Security Architecture Professional (“ISSAP”), and as a Certified Information Systems Security Professional (“CISSP”). Our CISO oversees compliance of our information security (“IS”) standards and mitigation of IS risks. We also have the following internal bodies to support our processes to assess and manage cybersecurity risk as follows:

• The Crisis Incident Management Team, which includes members of the executive management team, the CIO, CISO, and other senior executives across the Company, is alerted as appropriate to cybersecurity incidents, as well as other crises, such as natural disasters and outages. This team also periodically oversees tabletop drills on various cybersecurity incidents.
• The Cyber Risk Disclosure Committee brings together senior management, including the CEO, CFO, General Counsel and other relevant functions to review the materiality of cyber incidents for disclosure purposes. The Cyber Risk Disclosure Committee members are also part of the Crisis Incident Management team.
• The IT leadership team, led by our Chief Information Officer, oversees IT initiatives while considering cybersecurity risk mitigation with respect to these initiatives. The team provides periodic presentations to senior management and the Board on cybersecurity risk and mitigation.
• The VP of Technical and Maintenance chairs monthly cybersecurity meetings to review cyber risks or threats related to the operations of our geothermal projects.

At the level of the general employee population, we hold trainings on privacy and information security, records and information management, and information security regulatory compliance, conduct phishing tests and generally seek to promote awareness of cybersecurity risk through broad communication and educational initiatives, depending on the employee’s level, role and exposure to sensitive systems and the associated cybersecurity risk profile. We also contract with an external vendor to monitor alerts in real time on cybersecurity incidents.

With respect to third party service providers, we obligate our vendors to adhere to privacy and cybersecurity measures. We also restrict vendors’ access to our organizational systems through a segmented and controlled environment, which is monitored by us, and perform detailed and customized risk assessments of certain vendors, including their ability to protect data from unauthorized access.

Our main corporate offices are located at 6884 Sierra Center Drive in Reno, Nevada 89511 in the U.S, which property we currently own. We also occupy an approximately 807,000 square foot office and manufacturing facility located in the Industrial Park of Yavne, Israel, which we lease from the Israel Land Administration. See Item 13 — “Certain Relationships and Related Transactions”. In Turkey, we established and leased a facility to locally produce power plant components to our local customers.

We believe that our current offices and manufacturing facilities will be adequate for our operations as currently conducted.

Each of our power plants is located on property leased or owned by us or one of our subsidiaries or is a property that is subject to a concession agreement.

Information and descriptions of our plants and properties are included in Item 1 — “Business”.

The information required with respect to this item can be found under “Commitments and Contingencies” in Note 20 of the consolidated financial statements contained in Item 8 of this Annual Report and is incorporated by reference herein.

You should read the following discussion and analysis of our results of operations, financial condition and liquidity in conjunction with our consolidated financial statements and the related notes. Some of the information contained in this discussion and analysis or set forth elsewhere in this Annual Report including information with respect to our plans and strategies for our business, statements regarding the industry outlook, our expectations regarding the future performance of our business, and the other non-historical statements contained herein are forward-looking statements. See “Cautionary Note Regarding Forward-Looking Statements.” You should also review Item 1A — “Risk Factors” for a discussion of important factors that could cause actual results to differ materially from the results described herein or implied by such forward-looking statements.

General

Recent Developments

The most significant recent developments for our Company and business during 2025 and 2026 to date are described below:

• In February 2026, we entered into a long-term geothermal portfolio PPA to supply up to 150MW of new geothermal capacity to support Google’s data center’s energy needs, through NV Energy’s Clean Transition Tariff program. The portfolio structure is expected to enable the development of multiple new geothermal projects across Nevada, with energy deliveries anticipated to commence between 2028 and 2030 as projects reach commercial operations. Per the PPA structure, the contract term begins with the first geothermal project achieving commercial operations and extends 15 years beyond the final project’s commercial operations date. The agreement and related energy supply arrangements are subject to approval by the Nevada PUC, which is expected in the second half of 2026.
• In January 2026, we acquired Hoku, a recently built operational solar-plus-storage facility on the Big Island of Hawaii, from Innergex Renewable Energy Inc. for total cash consideration of $80.5 million. The acquired assets include a 30MW solar PV facility paired with a 30MW/120MWh battery energy storage system, which achieved commercial operation in March 2025 and is fully operational. All output from the facility is sold under a 25-year fixed-price power purchase agreement with HECO.
• In January 2026, we made a $25 million investment in Sage Geosystems Inc. (“Sage”) as part of Sage’s Series B financing round. This investment represents an important milestone in our strategy to expand our EGS portfolio and capabilities and supports the continued development and commercialization of next-generation geothermal technology. In August 2025, we also announced the signing of a strategic commercial agreement with Sage. Under the terms of the agreement, Sage will pilot its advanced pressure geothermal technology to extract geothermal heat energy from hot dry rock at an existing Ormat power plant. This collaboration aims to significantly reduce the time needed to bring geothermal energy to market and is expected to enhance the Company’s operational efficiency while accelerating the implementation of next-generation geothermal solutions. The strategic commercial agreement was closed.
• In January 2026, we were awarded the Telaga Ranu geothermal working area concession in Indonesia following a competitive tender process. The concession is located in Halmahera, North Maluku, within one of Indonesia’s highest approved feed-in tariff zones and has the potential to support up to approximately 40MW of baseload geothermal generation capacity. This award strengthens our long-term development pipeline and supports our continued growth strategy in Indonesia.
• In January 2026, we entered into a new 20-year PPA with Switch, Inc., a leading provider of data center infrastructure, pursuant to which Switch will purchase approximately 13MW of carbon-free geothermal capacity from our Salt Wells geothermal power plant located near Fallon, Nevada. Under the agreement, energy deliveries are scheduled to commence in the first quarter of 2030, following the completion of a planned major upgrade to the Salt Wells facility. As part of the agreement, we also have the option to further expand the facility’s output through the addition of an approximately 17MW solar PV facility to support the plant’s auxiliary power needs.
• In December 2025, we reached the COD for Arrowleaf, our first hybrid solar-plus-storage project, consisting of approximately 42MW of solar generation capacity and 35MW/140MWh of energy storage. The project operates

under a long-term tolling agreement with San Diego Community Power. In connection with the project’s COD, the related hybrid tax equity partnership transaction with Morgan Stanley Renewables, Inc. closed in December 2025 and resulted in approximately $38 million of upfront proceeds to the Company.

• In October 2025, the Company and SLB announced an agreement to fast-track the development and commercialization of integrated geothermal assets, including EGS. Together, Ormat and SLB intend to streamline project deployment, from concept to power generation. As part of this effort, SLB will develop, pilot and scale EGS solutions to enable wide-scale EGS adoption. This collaboration will include the design and construction of an EGS pilot at an Ormat site.
• In September 2025, we successfully commenced the commercial operations of our 60MW/120MWh Lower Rio energy storage facility, located in Texas.
• In August 2025, we signed two Geothermal Exploration and Energy Conversion Agreements (“GEECA”), a novel form of power purchase agreement, with Perusahaan Listrik Negara (“PLN”), each covering up to 20 MW of geothermal capacity each in Songa Wayaua and Atadei located in Indonesia. Under the terms of these agreements, the Company, through its project companies, will undertake the exploration drilling, financing, designing, constructing, installing, and operating the Geothermal Power Plant on a BOT (“Build, Operate and Transfer”) basis , with a 23 year operating term. PLN will reimburse the cost of successful drilling and retains the option to acquire up to a 30% equity interest in the project companies.
• In August 2025, we announced the signing of a 25-year extension to our existing power purchase agreement with SCPPA, for the 52MW from Heber 1 geothermal facility. This long-term agreement, which is effective February 2026, will ensure the continued delivery of clean, baseload geothermal energy to the Los Angeles Department of Water and Power and the Imperial Irrigation District. The Company will supply the SCPPA with electricity from the Ormat Heber 1 geothermal facility, located in the Imperial Valley of Southern California.
• In July 2025, we entered into loan agreements with a consortium of French banks pursuant to which we will borrow up to approximately €99.8 million aggregate principal amount in connection with our new Bouillante geothermal power plant in Guadeloupe.
• In July 2025, we entered into a tax partnership agreement with a private investor, under which the private investor paid approximately $77.1 million for the tax benefits related to the Heber 1&2 Geothermal power plants that are part of our Heber Complex. The private investor will pay over eight years additional installments that are expected to amount to approximately $25.7 million.
• In June, 2025, we entered into loan agreements with the Caribbean Development Bank and Caricom Development Fund pursuant to which we will borrow up to $49.8 million aggregate principal amount in connection with the 10MW Geothermal Project in Dominica.
• In June 2025, we closed the acquisition of the Blue Mountain geothermal power plant from Cyrq Energy. The 20MW facility, located in Humboldt County, NV, was purchased for $88.7 million for 100% of the equity interest in the power plant. The power plant, built using Ormat technology, features an existing 51MW interconnection capacity and a PPA with NV Energy that expires at the end of 2029. The Company plans to upgrade the power plant and increase its capacity by 3.5MW. Additionally, subject to permit and PPA approval, Ormat intends to add a 13MW solar facility to support the plant's auxiliaries.
• In May 2025, we announced the signing of a $62.0 million Hybrid Tax Equity partnership with Morgan Stanley Renewables, Inc. The partnership’s transaction covers the Lower Rio 60MW/120MWh storage facility and the Arrowleaf 35MW/140MWh storage and 42MW solar projects, which are expected to achieve COD by the end of 2025.
• In February 2025, we won a tender issued by the Israeli Electricity Authority and have been awarded two separate 15-year tolling agreements for two Energy Storage facilities. The facilities under the tolling agreements are expected to have a combined capacity of approximately 300MW/1200MWh. The ownership of the projects will be shared, 50/50 between Ormat and Allied Infrastructure LTD, a leading infrastructure company in Israel.
• In February 2025, we announced the successful COD for the Ijen geothermal power plant that is owned jointly with PT Medco Power Indonesia (“Medco Power”). The Ijen Geothermal Power Plant, equipped with Ormat Energy Converter, began operations with its first phase, delivering 35MW of electricity power to the Java grid, Ormat’s share of the facility is 17MW.
• In January 2025, we announced the signing of a 10-year PPA with Calpine Energy Solutions, one of North America’s largest energy suppliers. Under this agreement, Calpine Energy Solutions agreed to purchase up to 15MW of clean, renewable energy from the Mammoth 2 geothermal power plant located near Mammoth Lakes, California, to support demand within its retail portfolio. Energy deliveries under the PPA are scheduled to begin

in the first quarter of 2027 and will replace the existing PPA with Southern California Edison. The new PPA includes an increase in production capacity and a higher price point.

Opportunities, Trends and Uncertainties

Different trends, factors and uncertainties may impact our operations and financial condition, including many that we do not or cannot foresee. However, we believe that our results of operations and financial condition for the foreseeable future will be primarily affected by the following trends, factors and uncertainties that are from time to time also subject to market cycles:

• Increased Demand for Baseload and Data Centers: Demand for electricity generated from geothermal and other renewable resources in the United States has increased due to the need for reliable baseload power and the growing energy requirements of data centers. This demand is supported by legislative and regulatory initiatives, including state RPS and clean energy mandates, which encourage or require the procurement of renewable energy.
• Higher PPA Pricing in the United States: Increasing electricity demand from data centers and hyperscale customers has contributed to higher PPA pricing in the United States for new geothermal projects and for the renewal of PPAs scheduled to expire over the next few years. This trend may support improved profitability and increased future revenues from our operating assets; however, actual outcomes will depend on market conditions, and timing of contract renewals.
• Enhanced Geothermal Systems (“EGS”) Opportunities: Advancements in and viability of EGS technology may create opportunities for growth in both our Electricity and Product segments by expanding the range of geothermal resources that can be economically developed. EGS has the potential to enable power generation and equipment sales in locations that do not have naturally occurring hydrothermal resources, which could increase the addressable market for geothermal energy. The timing, scale and commercial viability of EGS development remain uncertain and will depend on technological progress, regulatory frameworks, capital availability and market conditions.
• Reduced Tolling prices for Storage Facilities in Texas: While tolling agreements for storage facilities were introduced in Texas, prices of new tolling arrangements has declined, and certain previously executed tolling agreements were cancelled. This shift is primarily driven by sustained low merchant power prices, which have reduced the economic attractiveness of tolling structures and increased exposure to merchant market volatility for storage projects.
• Local Support: We expect that a variety of local governmental initiatives will create new opportunities for the development of new projects with the potential to realize higher returns on our equity as well as to create additional markets for our products. These initiatives include the award of long-term contracts to independent power generators, the creation of competitive wholesale markets for selling and trading energy, capacity and related energy products and the adoption of programs designed to encourage “clean” renewable and sustainable energy sources.
• Product Segment Opportunities and Competition: In the Product segment, we believe there are new business opportunities in the U.S., Asia Pacific, New Zealand and Central and South America. We have experienced increased competition from binary power plant equipment suppliers including the major steam turbine manufacturers. While we believe that we have a distinct competitive advantage based on our technology, accumulated experience and current worldwide share of installed binary generation capacity, an increase in competition may impact our ability to secure new purchase orders from potential customers. The increased competition may also lead to further reductions in the prices that we are able to charge for our binary equipment.
• OBBBA Impact: On July 4, 2025, the OBBBA was signed into law by the President of the United States. Rules under the OBBBA were updated in August 2025. For more information, see Note 16 to the consolidated financial statements contained in this annual report. The Company is currently evaluating the impact of the OBBBA on its consolidated financial statements, however, it does not expect the impact to be material.
• New Tariffs: Throughout 2025, the United States introduced actions to increase import tariffs at various rates, including on certain products imported from almost all countries and individualized higher tariffs on certain other countries, such as China. Other countries have announced retaliatory actions or plans for retaliatory actions in response. Some of these tariff announcements were followed by limited exemptions and temporary pauses. As of the date of this annual report, discussions remain ongoing regarding U.S. trade restrictions and tariffs on imports

and retaliatory tariffs from numerous countries, and while certain of these tariffs and other trade restrictions have already taken effect, there continues to be significant uncertainty about the future relationship between the United States and other countries regarding such trade policies, treaties, and tariffs. Accordingly, we can make no assurance about the eventual impact on our operating results and business. Our Energy Storage segment growth relies on imported batteries from China, and the growth of projects in the United States in the Electricity segment requires raw materials and equipment from various countries.

While there has so far been only limited impact on short-term growth in both of these segments, a significant increase in tariffs may lead to a slowdown in the growth of our Energy Storage segment in the United States if we are unable to pass the price increases from tariffs through to our customers. This could affect our long-term growth targets, specifically in our Energy Storage segment in the United States, and, to a lesser extent, across our business. Additionally, increases in the cost of raw materials and equipment resulting from tariffs could increase our capital expenditures for projects built in the United States under our Electricity segment. We have worked to accelerate imports into the United States and have expedited Chinese imports prior to the potential reinstatement of higher tariffs. However, we can make no assurance that we will succeed in avoiding any of these negative consequences. In addition, current uncertainties about tariffs and their effects on trading relationships may contribute to inflation in the markets in which we operate. For more information, see Part II, Item 1A “Risk Factors”

• Inflation and Macroeconomic Trends: Higher rates of inflation, particularly in the U.S., have been observed over the last few years. While most international-based contracts are indexed to inflation, U.S. contracts are not. Although we see a moderation in the rate of inflation, if inflation continues to rise, it may increase expenses and impact profit margins. Additionally, macroeconomic trends, including a potential economic recession, changes in Federal Reserve monetary policy, the policies of the new presidential administration, and geopolitical risks, including ongoing Middle East tensions, may adversely affect our operations and financial condition.

Revenues

Sources of Revenues

We generate our revenues from the sale of electricity from our geothermal and recovered energy-based power plants; the design, manufacture and sale of equipment for electricity generation; the construction, installation and engineering of power plant equipment; and the sale of energy storage services and electricity from our operating energy storage facilities.

Electricity Segment

Revenues attributable to our Electricity segment are derived from the sale of electricity from our power plants pursuant to long-term PPAs. While approximately 93.8% of our Electricity revenues for the year ended December 31, 2025 were derived from PPAs with fixed price components, we have a variable price PPA in Hawaii, which provide for payments based on the local utilities’ avoided cost. The avoided cost is the incremental cost that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others. In Hawaii, the prices paid for electricity pursuant to the 25 MW PPA for the Puna Complex change primarily as a result of variations in the price of oil as well as other commodities. Accordingly, our revenues from this power plant may fluctuate. In 2024, the HPUC approved a new PPA related to Puna with fixed prices, increased capacity and an extension of the term until 2052, which we expect to be in effect in early 2027. Our Electricity segment revenues are also subject to seasonal variations, as more fully described in “Seasonality” below.

Our PPAs generally provide for energy payments alone, or energy and capacity payments. Generally, capacity payments are payments calculated based on the amount of time and capacity that our power plants are available to generate electricity. Energy payments are payments calculated based on the amount of electrical energy delivered to the relevant power purchaser at a designated delivery point. Our most recent PPAs generally provide for energy payments alone with an obligation to compensate the off-taker for its incremental costs as a result of shortfalls in our supply.

Revenues attributable to our Product segment are based on the sale of equipment, engineering, procurement and construction contracts and the provision of various services to our customers. Product segment revenues fluctuate between periods, primarily based on our ability to receive customer orders, the status and timing of such orders, delivery of raw materials and the completion of manufacturing. Larger customer orders for our products are typically the result of our sales efforts, our participation in, and winning tenders or requests for proposals issued by potential customers in connection with projects they are developing and orders by returning customers. Such projects often take a significant amount of time to design and develop and are subject to various contingencies, such as the customer’s ability to raise the necessary financing for a project. Consequently, we are generally unable to predict the timing of such orders for our products and may not be able to replace existing orders that we have completed with new ones. As a result, revenues from our Product segment fluctuate (sometimes extensively) from period to period.

Energy Storage Segment

Revenues attributable to our Energy Storage segment are generated by several grid-connected BESS facilities that we own and operate from selling energy, capacity and/or ancillary services in merchant markets like PJM Interconnect, ISO New England, ERCOT and CAISO or under tolling agreements that have fixed revenues. The revenues fluctuate over time since a large portion of such revenues are generated in the merchant markets, where price volatility is inherent. We are seeking to reduce volatility by increasing the amount of long-term tolling agreements in our portfolio. In the two solar PV plus energy storage facilities, although the solar capacity is included in the Electricity Segment portfolio, 100% of the revenues are recorded under the Energy Storage segment.

We are pursuing the development of additional grid-connected BESS projects in multiple regions, with expected revenues coming from providing energy, capacity and/or ancillary services on a merchant basis, and/or through bilateral fixed contracts with load serving entities, investor-owned utilities, publicly owned utilities and community choice aggregators.

Our management assesses the performance of our operating segments differently. In the case of our Electricity segment, when making decisions about potential acquisitions or the development of new projects, management typically focuses on the internal rate of return of the relevant investment, technical and geological matters and other business considerations. Management evaluates our operating power plants based on revenues, expenses, and EBITDA, and our projects that are under development based on costs attributable to each such project. Management evaluates the performance of our Product segment based on the timely delivery of our products, performance quality of our products, and revenues and costs actually incurred to complete customer orders compared to the costs originally budgeted for such orders. We evaluate our Energy Storage segment performance similar to the Electricity segment with respect to projects that we own and operate.

The following table sets forth a breakdown of our revenues for the years indicated:

(Dollars in thousands)

Geographic Breakdown of Results of Operations

The following table sets forth the geographic breakdown of the revenues attributable to our Electricity, Product and Energy Storage segments for the years indicated:

(Dollars in thousands)

76

In 2025, 2024 and 2023, 40%, 37% and 39% of our total revenues were derived from foreign locations, respectively, and our foreign operations had higher gross margins than our U.S. operations in each of those years. A substantial portion of the Electricity Segment foreign revenues came from Kenya and, to a lesser extent, from Honduras, Guadeloupe, and Guatemala. Our operations in Kenya contributed disproportionately to gross profit and net income. The contribution to combined pre-tax income of our domestic and foreign operations within our Electricity segment and Product segment differ in a number of ways, as summarized below.

Electricity Segment

Our Electricity segment domestic revenues were approximately 72%, 73% and 71% of our total Electricity segment for the years ended December 31, 2025, 2024 and 2023, respectively. However, domestic operations have higher costs of revenues and expenses than our foreign operations. Our foreign power plants are located in lower-cost regions, like Kenya, Guatemala, Honduras and Guadeloupe, which favorably impact payroll, and maintenance expenses among other items. Our power plants in foreign locations are also newer than most of our domestic power plants and therefore tend to have lower maintenance costs and higher availability factors than our domestic power plants. Consequently, in 2025 and 2024, our foreign operations of the segment accounted for 39% and 39% of our total gross profits, 49% and 48% of our net income (considering the majority of corporate operating and financing expenses are recorded under our domestic operations), and 29% and 31% of our EBITDA, respectively.

Our Product segment foreign revenues were 95%, 94% and 94% of our total Product segment revenues for the years ended December 31, 2025, 2024 and 2023, respectively.

Energy Storage Segment

Our Energy Storage segment domestic revenues were 100.0% of our total Energy storage segment revenues for years ended December 31, 2025, 2024 and 2023, respectively.

Seasonality

Electricity generation from some of our geothermal power plants is subject to seasonal variations. In the winter, our power plants produce more energy primarily attributable to the lower ambient temperature, which has a favorable impact on the energy component of our Electricity segment revenues as the prices under many of our contracts are fixed throughout the year with no time-of-use impact. The prices paid for electricity under the PPAs for the Mammoth Complex and the North Brawley power plant in California, the Raft River power plant in Idaho, the Neal Hot Springs power plant in Oregon and Dixie Valley power plant in Nevada, are higher in the months of June through September. The higher payments payable under these PPAs in the summer months partially offset the negative impact on our revenues from lower generation in the summer attributable to a higher ambient temperature. As a result, we expect the revenues and gross profit in the winter months to be higher than the revenues and gross profit in the summer months and in general we expect the first and fourth quarters to generate higher revenues than the second and third quarters. In the Storage segment pursuant to the Bottleneck tolling agreement, approximately 45% of the revenues are generated in the third quarter, and the rest is roughly even between the first, second and fourth quarters.

Breakdown of Cost of Revenues

Electricity Segment

The principal cost of revenues attributable to our operating power plants are operation and maintenance expenses comprised of salaries and related employee benefits, equipment expenses, costs of parts and chemicals, costs related to third-party services, lease expenses, royalties, startup and auxiliary electricity purchases, property taxes, insurance, depreciation and amortization and, for some of our projects, purchases of make-up water for use in our cooling towers. In our California power plants, our principal cost of revenues also includes transmission charges and scheduling charges. In some of our Nevada power plants we also incur transmission and wheeling charges. Some of these expenses, such as parts, third-party services and major maintenance, are not incurred on a regular basis. This results in fluctuations in our expenses and our results of operations for individual power plants from quarter to quarter. Payments made to government agencies and private entities on account of site leases where power plants are located are included in cost of revenues. Royalty payments, included in cost of revenues, are made as compensation for the right to use certain geothermal resources and are paid as a percentage of the revenues derived from the associated geothermal rights. Royalties constituted approximately 4.5% and 4.6% of Electricity segment revenues for the years ended December 31, 2025 and 2024, respectively.

The principal cost of revenues attributable to our Product segment are materials, salaries and related employee benefits, expenses related to subcontracting activities, and transportation expenses. Sales commissions to sales representatives are included in selling and marketing expenses. Some of the principal expenses attributable to our Product segment, such as a portion of the costs related to labor, utilities and other support services are fixed, while others, such as materials, construction, transportation and sales commissions, are variable and may fluctuate significantly, depending on market conditions. As a result, the cost of revenues attributable to our Product segment, expressed as a percentage of total revenues, fluctuates. Another reason for such fluctuation is that in responding to bids for our products, we price our products and services in relation to existing competition and other prevailing market conditions, which may vary substantially from order to order.

Energy Storage Segment

The principal cost of revenues attributable to our Energy Storage segment are direct costs of the BESS that we own, and depreciation and amortization. Direct costs include the labor associated with operations and maintenance of owned BESS. In addition, the cost of revenue includes insurance and property tax expenses.

Critical Accounting Estimates and Assumptions

Our significant accounting policies are more fully described in Note 1 to our consolidated financial statements set forth in Item 8 of this Annual Report. However, certain of our accounting policies are particularly important to an understanding of our financial position and results of operations. In applying critical accounting estimates and assumptions to our policies, our management uses its judgment to determine the appropriate assumptions to be used in making certain estimates. Such estimates are based on management’s historical experience, the terms of existing contracts, management’s observance of trends in the geothermal industry, information provided by our customers and information available to management from other outside sources, as appropriate. Such estimates are subject to an inherent degree of uncertainty and, as a result, actual results could differ from our estimates. Our critical accounting estimates include:

Revenues and Cost of Revenues

Revenues generated from the construction of geothermal and recovered energy-based power plant equipment and other equipment on behalf of third parties (Product revenues) are recognized using the percentage of completion method, which requires estimates of future costs over the full term of product delivery. Such cost estimates are made by management based on prior operations and specific project characteristics and designs. If management’s estimates of total estimated costs with respect to our Product segment are inaccurate, then the percentage of completion is inaccurate resulting in an over- or under-estimate of revenue and gross margin. As a result, we review and update our cost estimates on significant contracts on a quarterly basis, and at least on an annual basis for all others, or when circumstances change and warrant a modification to a previous estimate. Changes in job performance, job conditions, and estimated profitability, including those arising from the application of penalty provisions in relevant contracts and final contract settlements, may result in revisions to costs and revenues and are recognized in the period in which the revisions are determined. Provisions for estimated losses relating to contracts are made in the period in which such losses are determined. Revenues generated from engineering and operating services and sales of products and parts are recorded once the service is provided or product delivered as the customer obtains control of the asset, as applicable.

Electricity Property, Plant and Equipment

We capitalize all costs associated with the acquisition, development and construction of power plant facilities. Major improvements are capitalized and repairs and maintenance (including major maintenance) costs are expensed. We estimate the useful life of our power plants to range between 15 and 30 years. Such estimates are made by management based on factors such as prior operations, the terms of the underlying PPAs, geothermal resources, the location of the assets and specific power plant characteristics and designs. Changes in such estimates could result in useful lives which are either longer or shorter than the depreciable lives of such assets. We periodically re-evaluate the estimated useful life of our power plants and revise the remaining depreciable life on a prospective basis.

We capitalize costs incurred in connection with the exploration and development of geothermal resources beginning when we acquire land rights to the potential geothermal resource. Prior to acquiring land rights, we make an initial assessment that an economically feasible geothermal reservoir is probable on that land using available data and external assessments vetted through our exploration department and occasionally outside service providers. Costs incurred prior to acquiring land rights are expensed. It normally takes two to three years from the time we start active exploration of a particular geothermal resource to the time we have an operating production well, assuming we conclude the resource is commercially viable.

In most cases, we obtain the right to conduct our geothermal development and operations on land owned by the BLM, various states or with private parties. Once we acquire land rights to the potential geothermal resource, we perform additional activities to assess the commercial viability of the resource. Such activities include, among others, conducting surveys and other analysis, obtaining drilling permits, creating access roads to drilling sites, and exploratory drilling which may include temperature gradient holes and/or slim holes. Such costs are capitalized and included in construction-in-process. Once our exploration activities are complete, we finalize our assessment as to the commercial viability of the geothermal resource and either proceed to the construction phase for a power plant or abandon the site. If we decide to abandon a site, all previously capitalized costs associated with the exploration project are written off.

Our assessment of economic viability of an exploration project involves significant management judgment and uncertainties as to whether a commercially viable resource exists at the time we acquire land rights and begin to capitalize such costs. As a result, it is possible that our initial assessment of a geothermal resource may be incorrect and we will have to write off costs associated with the project that were previously capitalized. Due to the uncertainties inherent in geothermal exploration, historical impairments may not be indicative of future impairments. Included in construction-in-process are costs related to projects in exploration and development of $286.9 million and $193.7 million at December 31, 2025 and 2024, respectively.

Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of

We evaluate long-lived assets, such as property, plant and equipment and construction-in-process for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Factors which could trigger an impairment include, among others, significant underperformance relative to historical or projected future operating results, significant changes in our use of assets or our overall business strategy, negative industry or economic trends, a determination that an exploration project will not support commercial operations, a determination that a suspended project is not likely to be completed, a significant increase in costs necessary to complete a project, legal factors relating to our business or when we conclude that it is more likely than not that an asset will be disposed of or sold.

We test our operating plants that are operated together as a complex for impairment at the complex level because the cash flows of such plants result from significant shared operating activities. For example, the operating power plants in a complex are managed under a combined operation management generally with one central control room that controls all of the power plants in a complex and one maintenance group that services all of the power plants in a complex. As a result, the cash flows from individual plants within a complex are not largely independent of the cash flows of other plants within the complex. We test for impairment of our operating plants which are not operated as a complex, as well as our projects under exploration, development or construction that are not part of an existing complex, at the plant or project level. To the extent an operating plant becomes part of a complex in the future, we will test for impairment at the complex level.

Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated future net undiscounted cash flows expected to be generated by the asset. The significant assumptions that we use in estimating our undiscounted future cash flows include (i) projected generating capacity of the power plant and rates to be received under the respective PPA and (ii) projected operating expenses of the relevant power plant. Estimates of future cash flows used to test recoverability of a long-lived asset under development also include cash flows associated with all future expenditures necessary to develop the asset. If future cash flows are actually less than those used in such estimates, we may incur impairment losses in the future that could be material to our financial condition and/or results of operations.

If our assets are considered to be impaired, the impairment to be recognized is the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. We believe that for the year ended December 31, 2025, no impairment exists for any of our long-lived assets; however, estimates as to the recoverability of such assets may change based on revised circumstances.

Estimates of the fair value of assets require estimating useful lives and selecting a discount rate that reflects the risk inherent in future cash flows.

Obligations Associated with the Retirement of Long-Lived Assets

We record the fair market value of legal liabilities related to the retirement of our assets in the period in which such liabilities are incurred. These liabilities include our obligation to plug wells upon termination of our operating activities, the dismantling of our power plants upon cessation of our operations, and the performance of certain remedial measures related to the land on which such operations were conducted. When a new liability for an asset retirement obligation is recorded, we capitalize the costs of such liability by increasing the carrying amount of the related long-lived asset. Such liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. At retirement, we either settle the obligation for its recorded amount or report either a gain or a loss with respect thereto. Estimates of the costs associated with asset retirement obligations are based on factors such as prior operations, the location of the assets and specific power plant characteristics. We review and update our cost estimates periodically and adjust our asset retirement obligations in the period in which the revisions are determined. If actual results are not consistent with our assumptions used in estimating our asset retirement obligations, we may incur additional losses that could be material to our financial condition or results of operations.

Accounting for Income Taxes

Significant estimates are required to arrive at our consolidated income tax provision. This process requires us to estimate our actual current tax exposure and to make an assessment of temporary differences resulting from different treatments of items for tax and accounting purposes. Such differences result in deferred tax assets and liabilities which are included in our consolidated balance sheets. For those jurisdictions where the projected operating results indicate that realization of our net deferred tax assets is not more likely than not, a valuation allowance is recorded.

We evaluate our ability to utilize the deferred tax assets quarterly and assess the need for a valuation allowance. In assessing the need for a valuation allowance, we estimate future taxable income, including the impacts of the enacted tax law, the feasibility of ongoing tax planning strategies and the realizability of tax credits and tax loss carryforwards. Valuation allowances related to deferred tax assets can be affected by changes in tax laws, statutory tax rates, and future taxable income. In the future, if there is insufficient evidence that we will be able to generate sufficient future taxable income in the U.S., we may be required to record a valuation allowance, resulting in income tax loss in our Consolidated Statement of Operations.

In the ordinary course of business, there can be inherent uncertainty in quantifying our income tax positions. We assess our income tax positions and record tax benefits for all years subject to examination based upon management’s evaluation of the facts, circumstances and information available at the reporting date. For those tax positions where it is more likely than not that a tax benefit will be sustained, which is greater than 50% likelihood of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information, we recognize between 0 to 100% of the tax benefit. For those income tax positions where it is not more likely than not that a tax benefit will be sustained, we do not recognize any tax benefit in the consolidated financial statements. Resolution of uncertainties in a manner inconsistent with our expectations could have a material impact on our financial condition or results of operations.

New Accounting Pronouncements

See Note 1 to our consolidated financial statements set forth in Item 8 of this Annual Report for information regarding new accounting pronouncements.

Results of Operations

Our historical operating results in dollars and as a percentage of total revenues are presented below.

(Dollars in thousands, except earnings per share data)

80

Results as a percentage of revenues

81

Comparison of the year ended December 31, 2024 and the year ended December 31, 2023

A discussion of changes in our results of operations in 2024 compared to 2023 has been omitted from this Form 10-K, but may be found in “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” of our Form 10-K for the fiscal year ended December 31, 2024, filed with the SEC on February 27, 2025, which is incorporated by reference herein. This Form 10-K for the fiscal year ended December 31, 2024 is available free of charge on the SECs website at www.sec.gov (http://www.sec.gov) and at www.Ormat.com (http://www.Ormat.com), by clicking “Investors” located at the top of the home page.

Comparison of the Year Ended December 31, 2025 and the Year Ended December 31, 2024

Total Revenues

(Dollars in millions)

82

For the year ended December 31, 2025, our total revenues increased by 12.5% from $879.7 million in 2024 to $989.5 million in 2025. For the year ended December 31, 2025, our Electricity segment generated 70.1% of our total revenues, compared to 79.8% in the previous year, while our Product segment generated 21.9% of our total revenues, compared to 15.9% in the previous year, and our Energy Storage segment generated 8.0% of our total revenues, compared to 4.3% in the previous year.

Electricity Segment

Revenues attributable to our Electricity segment for the year ended December 31, 2025 were $693.9 million, compared to $702.3 million for the year ended December 31, 2024, representing a 1.2% decrease. This decrease of $8.4 million was mainly attributable to (i) a decrease of $18.6 million related to curtailments in the U.S., mainly from McGinness Hills, Mammoth, Tungsten and Dixie Valley; (ii) a decrease of $13.9 million as a result of a temporary reduction in generation in our Puna power plant, primarily related to wellfield issues and lower energy rates in 2025 compared to 2024; (iii) a decrease of $3.2 million related to the Stillwater power plant, primarily due to planned repowering of the power plant; and (iv) an additional reduction in revenues in lower amounts at a number of other power plants. This decrease in revenues was partially offset by the following increases in revenues: (i) an increase of $6.6 million related to the Blue Mountain power plant which was purchased in June 2025; (ii) an increase of $5.4 million related to the Beowawe repower project which commenced commercial operation in the second quarter of 2024; (iii) an increase of $8.9 million in the Dixie Valley power plant, net of curtailment, due to the unscheduled maintenance work in 2024; and (iv) additional increases in revenues in lower amounts at a number of other power plants, primarily in Kenya and Cove Fort in the amount of $5.7 million.

During the years ended December 31, 2025 and 2024, our consolidated power plants generated 7,493,287 MWh and 7,450,071 MWh, respectively, an increase of 0.6%. The generation in 2025 and 2024 was lower by 277,923 MWh and 121,299 MWh, respectively due to curtailments in our U.S. projects. The average prices during the years ended December 31, 2025 and 2024 were $92.6, and $94.3 per MWh, respectively, mainly due to Puna’s lower generation and energy rate.

Product Segment

Revenues attributable to our Product segment for the year ended December 31, 2025 were $216.7 million, compared to $139.7 million for the year ended December 31, 2024, representing a 55.2% increase. The increase is primarily related to the progress in our projects and timing of when revenues are recognized. During 2025 and 2024, Product revenues included projects primarily in New Zealand and Dominica.

Energy Storage Segment

Revenues attributable to our Energy Storage segment for the year ended December 31, 2025 were $79.0 million compared to $37.7 million for the year ended December 31, 2024, representing a 109.3% increase. This increase of $41.2 million is primarily related to: (i) $15.8 million higher revenues related to merchant rates at PJM storage facilities in 2025, compared to 2024. (ii) the East Flemington facility which commenced commercial operations in the first quarter of 2024, the Bottleneck and Montague energy storage facilities which commenced commercial operations in the fourth quarter of 2024 and the Lower Rio facility that commenced commercial operations in September 2025.

Total Cost of Revenues

(Dollars in millions)

Electricity Segment

Total cost of revenues attributable to our Electricity segment for the year ended December 31, 2025 was $496.0 million, compared to $459.5 million for the year ended December 31, 2024, representing a 7.9% increase. This increase of

$36.5 million is primarily attributable to: (i) an increase in power plants depreciation expenses of $20.0 million, as a result of our investments in our power plants; (ii) an increase of $8.3 million in property tax expenses primarily related to the CD4 power plant, the Heber complex, and the Steamboat power plant; (iii) an increase of $2.3 million in the Stillwater power plant as a result of maintenance work during the third quarter of 2025; (iv) an increase of $2.0 million related to the Blue Mountain power plant which was purchased in June 2025; and other smaller amount increases in several other power plants.

As a percentage of total Electricity revenues, the total cost of revenues attributable to our Electricity segment for the year ended December 31, 2025 was 71.5%, compared to 65.4% for the year ended December 31, 2024. This increase was primarily attributable to higher depreciation and property tax expenses in some of our power plants, as well as the impact of curtailments on our revenues, as described above. The cost of revenues attributable to our international power plants was 17.8% of our Electricity segment cost of revenues for the year ended December 31, 2025, compared to 18.3% for the year ended December 31, 2024.

Total cost of revenues attributable to our Product segment for the year ended December 31, 2025 was $170.7 million, compared to $113.9 million for the year ended December 31, 2024, representing a 49.8% increase from the prior year. This increase was primarily attributable to the higher revenues in 2025, compared to 2024, as well as the higher profitability of projects for which revenues were recognized in 2025, compared to projects for which revenues were recognized in 2024. As a percentage of total Product segment revenues, our total cost of revenues attributable to our Product segment for the year ended December 31, 2025 was 78.8%, compared to 81.6% for the year ended December 31, 2024.

Energy Storage Segment

Cost of revenues attributable to our Energy Storage segment for the year ended December 31, 2025 were $50.2 million as compared to $33.6 million in the year ended December 31, 2024. This increase of $16.6 million was mainly due to costs related to the new energy storage facilities that came online during 2024 and 2025 such as Bottleneck, Montague, East Flemington and Lower Rio as described above.

Research and Development Expenses

Research and development expenses for the year ended December 31, 2025 were $6.3 million, compared to $6.5 million for the year ended December 31, 2024, representing a 3.0% decrease.

Selling and Marketing Expenses

Selling and marketing expenses for the year ended December 31, 2025 were $18.9 million, compared to $17.7 million for the year ended December 31, 2024, representing a 6.8% increase. Selling and marketing expenses constituted 1.9% and 2.0% of total revenues for the years ended December 31, 2025 and 2024, respectively.

General and Administrative Expenses

General and administrative expenses for the year ended December 31, 2025 were $79.6 million, compared to $80.1 million for the year ended December 31, 2024, representing a 0.7% decrease or $0.5 million. The decrease was primarily attributable to legal fees related to a settlement agreement with a third-party battery systems supplier of $4.0 million, which was recorded in 2024, partially offset by other legal and consulting fees in 2025 compared to 2024, as well timing of when we incur services from our vendors.

General and administrative expenses for the year ended December 31, 2025 constituted 8.0% of total revenues for such period, compared to 9.1%, for the year ended December 31, 2024.

Other Operating Income

Other operating income for the year ended December 31, 2025 was $14.8 million compared to $9.4 million for the year ended December 31, 2024. Other operating income primarily represents the non-refundable portion of the recovery of damages received from a third-party battery systems supplier as part of a settlement agreement entered into in August 2024 for which all contingency conditions have been met, as further described under Note 1 to the consolidated financial statements. The increase in “Other operating income” year-over-year of $5.5 million, primarily relates to a full year period in 2025 during which all contingency conditions have been met, as compared to a shorter period of such in 2024.

Impairment of long-lived assets

Impairment of long-lived assets for the year ended December 31, 2025 was $12.1 million compared to $1.3 million for the year ended December 31, 2024. The impairment of long-lived assets in 2025 is primarily related to: (i) $7.2 million associated with the Brawley power plant write-off as a result of continuous losses primarily attributable to wellfield issues which have resulted in higher-than-expected operating costs and lower-than-expected electricity revenues; and (ii) $4.9 million associated with the expected termination of a waste heat agreement between the Company's wholly-owned subsidiary, OREG2, and its customer. The impairment of long-lived assets in 2024 is related to the termination of the waste heat agreement between the Company's wholly-owned subsidiary, OREG4, and its customer.

Write-off of Unsuccessful Exploration and Storage Activities

Write-offs of unsuccessful exploration and storage activities for year ended December 31, 2025 were $1.4 million compared to $3.9 million for the year ended December 31, 2024. These write-offs are primarily related to geothermal exploration projects that the Company decided to no longer pursue, as well as costs related to a number of battery energy storage projects that the Company decided to no longer develop and pursue.

Interest Income

Interest Income for the year ended December 31, 2025 was $6.0 million, compared to $7.9 million for the year ended December 31, 2024. Interest income is primarily related to interest earned on cash and cash equivalents held by the Company during the period. The decrease in interest income is primarily related to lower balances of cash and cash equivalents during 2025 compared to 2024, as well as lower average interest rate, year-over-year.

Interest Expense, Net

Interest expense, net, for the year ended December 31, 2025 was $141.9 million, compared to $134.0 million for the year ended December 31, 2024, representing a 5.8% increase. This increase of $7.8 million is primarily attributable to the new long-term loans entered into during 2025 and 2024 of $548.5 million and $514.6 million, respectively (net of deferred financing costs), and the issuance of the additional 2.50% senior convertible notes in July 2024. This increase was partially offset by an increase in the amount of interest capitalized due to an increase in the construction-in-process balance and lower interest expenses on other long-term loans as a result of regular principal payments.

Derivatives and Foreign Currency Transaction Gains (Losses)

Derivatives and foreign currency transaction gains (losses) for the year ended December 31, 2025 was a gain of $5.2 million, compared to a loss of $4.2 million for the year ended December 31, 2024. Derivatives and foreign currency transaction gains (losses) primarily includes gains and losses from foreign currency forward contracts which were not accounted for as hedge transactions, and the impact of changes in foreign currency exchange rates against the U.S. Dollar.

Income Attributable to Sale of Tax Benefits

Income attributable to the sale of tax benefits for the year ended December 31, 2025 was $66.7 million, compared to $73.1 million for the year ended December 31, 2024. This income primarily represents the value of PTCs and taxable income or loss generated by certain of our power plants allocated to investors under tax equity transactions, and to income related to the expected sale of transferable production tax credits under the existing IRA regulations. This decrease of $6.3 million is primarily related to lower generation in certain power plants and the buyout of Opal Geo in July 2024, partially offset by an increase in PTC rates.

Other Non-Operating Income (Expense), Net

Other non-operating income, net for the year ended December 31, 2025 was an income of $0.4 million, compared to an income of $0.2 million for the year ended December 31, 2024. Other non-operating income, net is primarily related to certain immaterial non-operating proceeds from various third-parties.

Income Taxes

Income tax (provision) benefit for the year ended December 31, 2025, was a benefit of $20.3 million, an increase of $4.0 million compared to an income tax benefit of $16.3 million for the year ended December 31, 2024. Our effective tax rate for the year ended December 31, 2025 and 2024, was (19.2)% and (14.1)%, respectively. The effective rate differs from the federal statutory rate of 21% for the year ended December 31, 2025 due to the generation of investment tax credits, a net benefit associated with the U.S. state effective tax rate, an expense recorded associated with unrecognized tax benefits, and the jurisdictional mix of earnings at differing tax rates from the federal statutory tax rate.

Equity in Earnings (losses) of Investees, net

Equity in earnings (losses) of investees, net in the year ended December 31, 2025, was a net gain of $1.0 million, compared to a net loss of $0.4 million in the year ended December 31, 2024. Equity in earnings (losses) of investees, net is mainly derived from our 12.75% share in the earnings or losses in the Sarulla project, and our 49% share in the earnings or losses in the Ijen geothermal project. The increase in this line item is primarily related to an increase in net income generated by the Ijen project in 2025, compared to 2024. In the second quarter of 2022, Sarulla agreed with its banks on a framework that will enable it to perform remediation works that are aimed to restore the power plants' performance. The first phase of the recovery plan included the drilling of an additional production well, which was successful, and certain modifications to surface equipment are still underway. Following the positive indications from the first phase, during the second quarter of 2024, Sarulla commenced discussions with the banks towards implementation of the additional phases and expects to commence drilling of additional two wells, in 2026, aiming for the same target zone of the successful well drilled earlier.

Net Income attributable to the Company’s Stockholders

Net income attributable to the Company’s stockholders for the year ended December 31, 2025 was $123.9 million, compared to $123.7 million for the year ended December 31, 2024, which represents an increase of $0.2 million. This increase was attributable to the decrease in net income which was affected by the factors described above, as well as a decrease of $4.4 million in net income attributable to noncontrolling interest which is primarily related to the noncontrolling share in the net results of the Puna and Guadeloupe power plants.

Liquidity and Capital Resources

Overview of Sources and Uses of Cash

Our principal sources of liquidity have been derived from cash flows from operations, proceeds from third-party debt such as borrowings under our credit facilities and issuances of debt securities, equity offerings, project financing and tax monetization transactions, short term borrowing under our lines of credit, proceeds from the sale of equity interests in one or more of our projects and sale of transferable PTCs. We have utilized this cash to develop and construct power plants, storage facilities, fund our acquisitions, pay down existing outstanding indebtedness, and meet our other cash and liquidity needs.

Based on current conditions, we believe that we have sufficient financial resources to fund our activities and execute our business plans. However, the cost of obtaining financing for our project needs may increase significantly or such financing may be difficult to obtain.

As of December 31, 2025, we had access to: (i) $147.4 million in cash and cash equivalents, of which $75.4 million was held by our foreign subsidiaries; and (ii) $388.9 million of unused corporate borrowing capacity under existing committed lines for credit and letters of credit with different commercial banks.

As of December 31, 2025, $286.0 million in the aggregate was outstanding under different credit agreements with several banks as detailed below under “Letters of Credits under the Credit Agreements”.

Our estimated capital needs for 2026 include approximately $675.0 million for capital expenditures on new projects under development or construction including storage projects, exploration activity, investment in EGS pilot and maintenance capital expenditures for our existing projects. In addition, we expect $303.7 million for long-term debt repayments.

Our capital expenditures primarily relate to the enhancement of our existing power plants and the construction of new power plants. We have budgeted approximately $808.0 million in capital expenditures for construction of new projects and enhancements to our existing power plants, of which we had invested $208.0 million as of December 31, 2025. We expect to invest approximately $240.0 million in 2026 and the remaining approximately $360.0 million on thereafter.

In addition, we estimate approximately $435.0 million in additional capital expenditures in 2026 to be allocated as follows: (i) approximately $170.0 million for the exploration, drilling and development of new projects and enhancements of existing power plants that are not yet released for full construction; (ii) approximately $10 million for EGS pilot (iii) approximately $55.0 million for maintenance of capital expenditures to our Electricity segment operating power plants; (iv) approximately $180.0 million for the construction and development of storage projects; (v) approximately $10 million for land acquisition and other business development initiatives and (vi) approximately $10.0 million for enhancements to our production facilities.

We expect to finance these requirements with: (i) the sources of liquidity described above; (ii) positive cash flows from our operations; and (iii) future project financings and re-financings (including construction loans and tax equity). Management believes that, based on the current stage of implementation of our strategic plan, the sources of liquidity and capital resources described above will address our anticipated liquidity, capital expenditures, and other investment requirements.

Letters of Credits under the Credit Agreements

Some of our customers require our project subsidiaries to post letters of credit in order to guarantee their respective performance under relevant contracts. We are also required to post letters of credit to secure our obligations under various leases and licenses and may, from time to time, decide to post letters of credit in lieu of cash deposits in reserve accounts under certain financing arrangements. In addition, our subsidiary, Ormat Systems, is required from time to time to post performance letters of credit in favor of our customers with respect to orders of products.

The table below describes our committed and non-committed lines:

Credit Agreements

Credit Agreement with MUFG Union Bank

Ormat Nevada has a credit agreement with MUFG Union Bank under which it has an aggregate available credit of up to $100.0 million as of December 31, 2025. The credit termination date is June 30, 2026.

The facility is limited to the issuance, extension, modification or amendment of letters of credit. Union Bank is currently the sole lender and issuing bank under the credit agreement, but is also designated as an administrative agent on behalf of banks that may, from time to time in the future, join the credit agreement as lenders. In connection with this transaction, the Company entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which the Company agreed to guarantee Ormat Nevada’s obligations under the credit agreement. Ormat Nevada’s obligations under the credit agreement are otherwise unsecured. As of December 31, 2025, letters of credit in the aggregate amount of $80.0 million were issued and outstanding under this credit agreement.

Credit Agreement with HSBC Bank USA N.A.

Ormat Nevada has a credit agreement with HSBC Bank USA, N.A for one year with annual renewals. The current expiration date of the facility under this credit agreement is October 31, 2026. On December 31, 2025, the aggregate amount available under the credit agreement was $35.0 million. This credit line is limited to the issuance, extension, modification or amendment of letters of credit. In addition, Ormat Nevada has an uncommitted discretionary demand line of credit in the aggregate amount of $65.0 million available for letters of credit including up to $40 million of credit. In connection with this transaction, the Company entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which the Company agreed to guarantee Ormat Nevada’s obligations under the credit agreement. Ormat Nevada’s obligations under the credit agreement are otherwise unsecured. As of December 31, 2025, letters of credit in the aggregate amount of $33.7 million were issued and outstanding under the committed portion of this credit agreement and $21.6 million under the uncommitted portion of the agreement.

Restrictive Covenants

Our obligations under the credit agreements, the loan agreements, and the trust instrument, are unsecured, but we are subject to a negative pledge in favor of the banks and the other lenders and certain other restrictive covenants. These include, among other things, a prohibition on: (i) creating any floating charge or any permanent pledge, charge or lien over our assets without obtaining the prior written approval of the lender; (ii) guaranteeing the liabilities of any third-party without obtaining the prior written approval of the lender; and (iii) selling, assigning, transferring, conveying or disposing of all or substantially all of our assets, or a change of control in our ownership structure. Some of the credit agreements, the term loan agreements, and the trust instrument contain cross-default provisions with respect to other material indebtedness owed by us to any third-party. In some cases, including the credit agreements with MUFG Union Bank and with HSBC Bank USA N.A., we have agreed to maintain certain financial ratios, which are measured quarterly, such as: (i) equity of at least $750 million and in no event less than 25% of total assets; and (ii) 12-month debt, net of cash, cash equivalents, and short-term bank deposits to Adjusted EBITDA ratio not to exceed 6. As of December 31, 2025: (i) total equity was $2,680.9 million and the actual equity to total assets ratio was 42.9%; and (ii) the 12-month debt, net of cash and cash equivalents to Adjusted EBITDA ratio was 4.36. During the year ended December 31, 2025, we distributed interim dividends in an aggregate amount of $29.1 million. The failure to perform or observe any of the covenants set forth in such agreements, subject to various cure periods, would result in the occurrence of an event of default and would enable the lenders to accelerate all amounts due under each such agreement.

As described above, we are currently in compliance with our covenants with respect to the credit agreements, the loan agreements, except as described below, and the trust instrument, and believe that the restrictive covenants, financial ratios and other terms of any of our full-recourse bank credit agreements will not materially impact our business plan or operations.

As of December 31, 2025, we did not meet the dividend distribution criteria related to the DAC 1 Senior Secured Notes, which resulted in certain equity distribution restrictions from this related subsidiary. As of December 31, 2025, the amount restricted for distribution by this subsidiary was $1.0 million. There were no restrictions on the retained earnings or net income of Ormat Technologies, Inc., as the parent company, in respect of these matters, as of December 31, 2025.

Future minimum payments

Material future minimum payments under long-term obligations as of December 31, 2025, are detailed under the caption Contractual Obligations and Commercial Commitments, below and under Note 11 to the consolidated financial statements.

Third-Party Debt

Our third-party debt consists of (i) non-recourse and limited-recourse project finance debt or acquisition financing that we or our subsidiaries have obtained for the purpose of developing and constructing, refinancing or acquiring our various projects; (ii) full-recourse debt incurred by us or our subsidiaries for general corporate purposes; (iii) convertible senior notes; (iv) commercial paper; (iv) financing liability; and (v) short term revolving credit lines with banks. Further details related to our third-party debt are provided under Note 11 to the consolidated financial statements.

Non-recourse debt refers to debt involving debt repayments that are made solely from the power plant’s revenues (rather than our revenues or revenues of any other power plant) and generally are secured by the power plant’s physical assets, major contracts and agreements, cash accounts and, in many cases, our ownership interest in our affiliate that owns that power plant. These forms of financing are referred to as “project financing”.

In the event of a foreclosure after a default, our affiliate that owns the power plant would only retain an interest in the power plant assets, if any, remaining after all debts and obligations have been paid in full. In addition, incurrence of debt by a power plant may reduce the liquidity of our equity interest in that power plant because the equity interest is typically subject both to a pledge in favor of the power plant’s lenders securing the power plant’s debt and to transfer and change of control restrictions set forth in the relevant financing agreements.

Limited recourse debt refers to project financing as described above with the addition of our agreement to undertake limited financial support for our affiliate that owns the power plant in the form of certain limited obligations and contingent liabilities. These obligations and contingent liabilities may take the form of guarantees of certain specified obligations, indemnities, capital infusions and agreements to pay certain debt service deficiencies. Creditors of a project financing of a particular power plant may have direct recourse to us to the extent of these limited recourse obligations.

Non-Recourse and Limited-Recourse Third-Party Debt:

(Dollars in millions)

(1) Secured by equity interest.

(2) Secured by the assets.

(3) 3-month EUROBOR+1.8%

(4) 3-month EUROBOR+2.0%

Full-Recourse Third-Party Debt:

(Dollars in millions)

89

(1) The Discount 2024 II Loan bears an annual interest of 3-month Term SOFR plus 2.35%, but not less than Term SOFR of 2.5%.

(2) Bonds issued in total aggregate principal amount of NIS 1.0 billion.

Other Third-Party Debt

(Dollar in millions)

For additional description of our long-term debt, see Note 11 to our consolidated financial statements, set forth in Item 8 of this Annual Report.

Liquidity Impact of Uncertain Tax Positions

As discussed in Note 16 - Income Taxes, to our consolidated financial statements set forth in Item 8 of this Annual Report, we have a liability associated with unrecognized tax benefits and related interest and penalties in the amount of approximately $10.4 million as of December 31, 2025. This liability is included in long-term liabilities in our consolidated balance sheet, because we generally do not anticipate that settlement of the liability will require payment of cash within the next 12 months. We are not able to reasonably estimate when we will make any cash payments required to settle this liability.

Dividends

We have adopted a dividend policy pursuant to which we currently expect to distribute at least 20% of our annual profits available for distribution by way of quarterly dividends. In determining whether there are profits available for distribution, our Board will take into account our business plan and current and expected obligations, and no distribution will be made that in the judgment of our Board would prevent us from meeting such business plan or obligations.

The following are the dividends declared by us during the past two years, as of December 31, 2025 :

Historical Cash Flows

The following table sets forth the components of our cash flows for the relevant periods indicated:

(Dollars in thousands)

For the Year Ended December 31, 2025

Net cash provided by operating activities for the year ended December 31, 2025 was $335.1 million, compared to $410.9 million for the year ended December 31, 2024, representing a net decrease of $75.8 million. Net cash provided by operating activities for the year ended December 31, 2025, was primarily attributable to net income of $127.0 million adjusted for certain non-cash items such as depreciation and amortization, stock-based compensation, income attributable to sale of tax benefits, impairment charges, and deferred income tax provision, among others, as well as primarily by: (i) net increase of $60.5 million in costs and estimated earnings in excess of billings on uncompleted contracts and billings in excess of costs and estimated earnings on uncompleted contracts, as a result of timing of billing to our customers; (ii) a net increase of $7.2 million in inventory primarily related to the progress of our Product projects and timing of allocating costs to such projects; and (iii) a net decrease in accounts payable and accrued expenses of $1.8 million as a result of timing of payments to our suppliers. This decrease was partially offset by (i) cash inflow related to the net decrease in trade receivables of $4.5 million, due to the timing of collection from our customers; and (ii) a net decrease in deposits and other of $5.8 million, primarily related to certain refunds. Net cash provided by operating activities for the year ended December 31, 2024 was $410.9 million, compared to $309.4 million for the year ended December 31, 2023, representing a net increase of $101.5 million. Net cash provided by operating activities for the year ended December 31, 2024, was primarily attributable to net income of $131.2 million adjusted for certain non-cash items such as depreciation and amortization, stock-based compensation, and income attributable to sale of tax benefits, among others, as well as primarily by: (i) cash inflow related to the net decrease in trade receivables of $27.2 million, due to the timing of collection from our customers; (ii) a net increase in accounts payable and accrued expenses of $11.4 million as a result of timing of payments to our suppliers, and a payment related to recovery of damages received from a third-party battery systems supplier as part of a settlement agreement; (iii) a net increase in prepaid expenses and other of $8.5 million, primarily as a result of timing of prepayments to our suppliers and governmental authorities; and (iv) a net decrease of $6.9 million in inventory, primarily related to the progress of our Product projects and timing of allocating costs to such projects. This increase was partially offset a net increase of $32.3 million in costs and estimated earnings in excess of billings on uncompleted contracts and billings in excess of costs and estimated earnings on uncompleted contracts, as a result of timing of billing to our customers, and a net increase in deposit and others of $4.5 million related to timing of payment deposits required for ongoing operations.

Net cash used in investing activities for the year ended December 31, 2025 was $726.4 million, compared to $780.3 million for the year ended December 31, 2024. The principal factors that affected the decrease of $53.8 million in our net cash used in investing activities during the year ended December 31, 2025 were cash consideration of $88.7 million paid for the acquisition of the Blue Mountain power plant in 2025, compared to cash consideration of $274.6 million paid for the purchase transaction with Enel EGPNA in 2024, partially offset by capital expenditures of $619.8 million in 2025 compared to $487.7 million in 2024, primarily for our geothermal power plants and storage facilities under construction that support our growth plan.

Net cash provided by financing activities for the year ended December 31, 2025 was $465.7 million, compared to $287.9 million for the year ended December 31, 2024. The principal factors that affected the increase in net cash provided by financing activities during the year ended December 31, 2025 were: (i) net proceeds of $548.5 million from long-term loans entered into during 2025; (ii) net proceeds related to tax monetization transactions of $152.0 million; (iii) net proceeds from revolving credit lines with banks of $80.0 million; and cash received from noncontrolling interest of $10.3 million. These cash inflows were partially offset by: (i) scheduled repayments of long-term debt in the amount of $265.5 million; (ii) cash dividend payments of $29.1 million; and (iii) cash paid in respect of debt and tax monetization transactions issuance costs of $20.8 million. The principal factors that affected net cash provided by financing activities during the year ended December 31, 2024 were: (i) net proceeds of $514.6 million from long-term loans entered into during the period such as the Hapoalim 2024 Loan, the HSBC 2024 Loan, the Mammoth Senior Secured Notes, the DEG 4 Loan, the Discount 2024 Loan, the Discount 2024 II Loan, and the Bottleneck Loan; (ii) net proceeds of $44.0 million related to proceeds from issuance of the Additional Notes; and (iii) cash received from noncontrolling interest in the amount of $12.3 million. These cash inflows were partially offset by: (i) scheduled repayments of long-term debt in the amount of $209.3 million; (ii) cash dividend payments of $29.1 million; (iii) cash paid pursuant to a transaction with noncontrolling interest of $9.8 million; and (iv) net repayments of revolving credit lines with banks of $20.0 million.

For the Year Ended December 31, 2024

A discussion of changes in our cash flows in 2024 compared to 2023 has been omitted from this Form10-K, but may be found in “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” of our Form 10-K for the fiscal year ended December 31, 2024, filed with the SEC on February 27, 2025, which is incorporated by reference herein. This Form 10-K is available free of charge on the SECs website at www.sec.gov (http://www.sec.gov) and at www.Ormat.com (http://www.Ormat.com), by clicking “Investors” located at the top of the home page.

Total EBITDA and Adjusted EBITDA

We calculate EBITDA as net income before interest, taxes, depreciation, amortization and accretion. We calculate Adjusted EBITDA as net income before interest, taxes, depreciation, amortization and accretion, adjusted for (i) mark-to-market gains or losses from accounting for derivatives not designated as hedging instruments; (ii) stock-based compensation; (iii) merger and acquisition transaction costs; (iv) gain or loss from extinguishment of liabilities; (v) costs related to settlement agreements; (vi) non-cash impairment charges; (vii) write-off of unsuccessful exploration and storage activities; (viii) allowance for bad debts; and (ix) other unusual or non-recurring items. We adjust for these factors as they may be non-cash, unusual in nature and/or are not factors used by management for evaluating operating performance. We believe that presentation of these measures will enhance an investor’s ability to evaluate our financial and operating performance. EBITDA and Adjusted EBITDA are not measurements of financial performance or liquidity under accounting principles generally accepted in the U.S., or U.S. GAAP, and should not be considered as an alternative to cash flow from operating activities or as a measure of liquidity or an alternative to net earnings as indicators of our operating performance or any other measures of performance derived in accordance with U.S. GAAP. Our Board of Directors and senior management use EBITDA and Adjusted EBITDA to evaluate our financial performance. However, other companies in our industry may calculate EBITDA and Adjusted EBITDA differently than we do.

This information should not be considered in isolation from, or as a substitute for, or superior to, measures of financial performance prepared in accordance with GAAP or other non-GAAP financial measures.

Net income for the year ended December 31, 2025 was $127.0 million, compared to $131.2 million for the year ended December 31, 2024 and $133.1 million for the year ended December 31, 2023.

Adjusted EBITDA for the year ended December 31, 2025 was $582.0 million, compared to $550.5 million for the year ended December 31, 2024 and $481.7 million for the year ended December 31, 2023.

The following table reconciles net income to EBITDA and Adjusted EBITDA for the years ended December 31, 2025, 2024 and 2023:

(Dollars in thousands)

Adjusted EBITDA for the fiscal year 2025 increased by 5.7% compared to fiscal year 2024, primarily due to an increase in EBITDA of $27.2 million, or 5.3%, as illustrated above. EBITDA and Adjusted EBITDA include our proportionate share (12.75% and 49%) of Sarulla's and Ijen EBITDA and Adjusted EBITDA, respectively. As of December 31, 2025, the outstanding carrying value of long-term debt owed by Sarulla and Ijen, our unconsolidated investments, was $645.3 million, and $105.0 million, respectively, in which our proportionate share was $82.3 million, and $51.5 million, respectively.

Exposure to Market Risks

We, like other power plant operators, are exposed to electricity price volatility risk. Our exposure to such market risk is currently limited because the majority of our long-term PPAs have fixed or escalating rate provisions that limit our exposure to changes in electricity prices, except for 25 MW PPA for the Puna complex. Our energy storage projects sell primarily on a "merchant" basis and are exposed to changes in the electricity market prices. The prices paid for electricity pursuant to the 25MW PPA for the Puna Complex in Hawaii change primarily as a result of variations in the price of oil as well as other commodities. Accordingly, our revenues from this power plant may fluctuate. In 2024, the HPUC approved a new PPA related to Puna with fixed prices, increased capacity and an extension of the term until 2052, which we expect to be in effect in early 2027.

As of December 31, 2025, 84.3% of our consolidated long-term debt was at fixed interest rates and therefore was not subject to interest rate volatility risk. Our variable interest rate long-term debt, as of the aforementioned date, is predominantly associated with either the 3-month SOFR or EUROBOR rate, as further detailed under Note 11 to the consolidated financial statements. Additionally, our short-term commercial paper, which was issued on October 23, 2023, bears an annual interest of 3-months SOFR+1.1%, and therefore present an exposure to interest rate volatility. The outstanding amount of the short-term commercial paper as of December 31, 2025 was $100.0 million.

Our cash equivalents are subject to interest rate risk. We currently maintain our surplus cash in short-term, interest-bearing bank deposits, money market funds, corporate bonds and debt securities available for sale (with a minimum investment grade rating of A+ by Standard & Poor’s Ratings Services).

We are also exposed to foreign currency exchange risk, in particular the fluctuation of the U.S. dollar versus the New Israeli Shekels ("NIS") in Israel, the Euro in Guadeloupe, and the New-Zealand Dollar in respect with our operation there. Risks attributable to fluctuations in currency exchange rates can arise when we, or any of our foreign subsidiaries, borrow funds or incur operating or other expenses in one type of currency but receive revenues in another. In such cases, an adverse change in exchange rates can reduce such subsidiary’s ability to meet its debt service obligations, reduce the amount of cash and income we receive from such foreign subsidiary, or increase such subsidiary’s overall expenses. In Kenya, the tax related asset and liability are recorded in Kenyan Shillings ("KES"), therefore, any change in the exchange rate in the KES versus the U.S. dollar has an impact on our financial results. Risks attributable to fluctuations in the foreign currency exchange rates can also arise when the currency denomination of a particular contract is not the U.S. dollar. Substantially all of our PPAs in the international markets are either U.S. dollar-denominated or linked to the U.S. dollar except for our operations on Guadeloupe, where we own and operate the Bouillante power plant which sells its power under a Euro-denominated PPA with Électricité de France S.A. Our construction contracts from time to time contemplate costs which are incurred in local currencies. The way we often mitigate such risk is to receive part of the proceeds from the contract in the currency in which the expenses are incurred. Currently, we have forward and cross-currency swap contracts in place to reduce our NIS/U.S. dollar currency exposure related to our Senior Unsecured Bonds - Series 4, as detailed below, and expect to continue to use currency exchange and other derivative instruments to the extent we deem such instruments to be the appropriate tool for managing such exposure.

On July 1, 2020, we concluded an auction tender and accepted subscriptions for senior unsecured bonds comprised of NIS 1.0 billion aggregate principal amount (the “Senior Unsecured Bonds - Series 4”). The Senior Unsecured Bonds - Series 4 were issued in New Israeli Shekels and converted to approximately $290 million using a cross-currency swap transaction shortly after the completion of such issuance. In June 2022, we issued $431.3 million aggregate principal amount of our 2.5% convertible senior notes due in 2027. The Notes bear annual interest of 2.5%, payable semiannually in arrears, and mature on July 15, 2027, unless earlier converted, redeemed or repurchased. In July 2024, we issued an additional $45.2 million aggregate principal amount of our 2.50% convertible senior notes due 2027 under the same terms.

We performed a sensitivity analysis on the fair values of our long-term debt obligations, commercial paper, and foreign currency exchange forward contracts. The foreign currency exchange forward contracts listed below principally relate to trading activities. The sensitivity analysis involved increasing and decreasing forward rates at December 31, 2025 and 2024 by a hypothetical 10% and calculating the resulting change in the fair values.

Currently, the development of our strategic plan has not exposed us to any additional market risk. However, as the implementation of the plan progresses, we may be exposed to additional or different market risks.

The results of the sensitivity analysis calculations as of December 31, 2025 and 2024 are presented below:

(In thousands)

94

Effect of Inflation

Over the last five years, although to a lesser extent during 2024 and 2025, we experienced an increase in the overall operating and other costs as a result of higher inflation rates, in particular in the U.S. To address the possibility of rising inflation, some of our contracts include certain provisions that mitigate inflation risk.

In connection with the Electricity segment, none of our U.S. PPAs, including the SCPPA Portfolio PPA, are directly linked to the Consumer Price Index ("CPI"), although some of them have a fixed annual indexation. Inflation may directly impact the expenses we incur for the operation of our projects, thereby increasing our overall operating costs and reducing our profit and gross margin. The negative impact of inflation would be partially offset by price adjustments built into some of our PPAs that could be triggered upon such occurrences. In addition to the Puna rates that are impacted by higher commodity prices, the energy payments pursuant to our PPAs for some of our power plants such as the Brady power plant, the Steamboat 2 and 3 power plants and the McGinness Complex increase every year through the end of the relevant terms of such agreements, although such increases are not directly linked to the CPI or any other inflationary index. Lease payments are generally fixed, while royalty payments are generally calculated as a percentage of revenues and therefore are not significantly impacted by inflation. In our Product segment, inflation may directly impact fixed and variable costs incurred in the construction of third-party power plants, thereby lowering our profit margins at the Product segment. We are more likely to be able to offset long term, all or part of this inflationary impact through our project pricing. With respect to power plants that we build for our own electricity production, inflationary pricing may impact our operating costs which may be partially offset in the pricing of the new long-term PPAs that we negotiate.

Interest rate for both short-term and long-term debt have increased sharply until 2024 and 2025 during which rates started to come down. Although our outstanding debt bears fixed interest rates, as we refinance it, or borrow additional amounts, we may incur additional interest expense versus expiring loans.

In recent months, we see a slowdown in inflation rates and increases in raw materials costs that we believe have returned to normal levels.

Contractual Obligations and Commercial Commitments

The following tables set forth our material contractual obligations as of December 31, 2025 :

(Dollars in thousands)

(1) Interest rates and maturity dates are detailed under the Liquidity and Capital Resources section above.

The above table does not reflect a liability associated with the sale of tax benefits of $190.2 million. Refer to Note 12 to our consolidated financial statements as set forth in Item 8 of this Annual Report for additional discussion of our liability associated with the sale of tax benefits.

Concentration of Credit Risk

Our credit risk is currently concentrated with the following major customers: Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy), SCPPA, and KPLC. If any of these electric utilities fail to make payments under their respective PPAs with us, such failure would have a material adverse impact on our financial condition. Also, by implementing our multi-year strategic plan we may be exposed, by expanding our customer base, to different credit profile customers than our current customers.

The Company's revenues from its primary customers as a percentage of total revenues are as follows:

We have historically been able to collect on substantially all of our receivable balances. As of December 31, 2025, the amount overdue from KPLC in Kenya was $29.5 million of which $21.1 million was paid in January and February of 2026. The Company believes it will be able to collect all past due amounts in Kenya. This belief is supported by the fact that in addition to KPLC's obligations under its power purchase agreement, the Company holds a support letter from the Government of Kenya that covers certain cases of KPLC non-payment (such as non-payments that are caused by government actions and/or political events).

In Honduras, as of December 31, 2025, the total amount overdue from ENEE was $20.3 million of which $1.0 million was collected in January and February of 2026. In addition, due to the financial situation in Honduras, the Company may experience additional delays in collection. The Company believes it will be able to collect all past due amounts in Honduras.

Government Grants and Tax Benefits

On July 4, 2025, the OBBBA was enacted into law in the United States. The OBBBA includes significant provisions, such as the permanent extension of certain expiring provisions of the Tax Cuts and Jobs Act of 2017 and numerous changes to the energy tax credits initially introduced and expanded under the IRA. The OBBBA allows for geothermal and battery storage to qualify for 100% PTC or ITC related to projects that start construction by the end of December 2033, 75% PTC or ITC by the end of December 2034 and 50% PTC or ITC by the end of December 2035. In order to qualify for 100% energy credit, solar projects must start construction by July 4, 2026 and be placed-in-service within four years, or start construction after July 3, 2026 and be placed-in-service by December 31, 2027. The law seeks to limit content from foreign entities of concern (“FEOC”) used in energy related projects that start construction after December 31, 2025. The FEOC restrictions apply at both the product and taxpayer levels, which primarily affects products and ownership related to China.

We are currently permitted to depreciate most of the cost of a new geothermal power plant. In cases where we claim ITCs, our tax basis in the plant that is eligible for depreciation is reduced by one-half of the ITC amount. In cases where we claim the PTC, there is no reduction in the tax basis for depreciation. Projects that were placed in service after September 27, 2017, could qualify for a 100% bonus depreciation with respect to its qualifying assets. After applying any depreciation bonus that is available, we are currently permitted to depreciate the remainder of our tax basis in the plant, if any, mostly over five years on an accelerated basis, meaning that more of the cost may be deducted in the first few years than during the remainder of the depreciation period. We will continue to analyze the current provision under the OBBBA and determine if an election is appropriate as it relates to our business needs. Future presidential administrations may take action to revise, repeal, or otherwise modify existing rules and regulations, including various tax incentives, and the potential impact on the Company remains uncertain at this time. For more information, see Part I of this Annual Report, Item 1A “Risk Factors—Risks Related to Governmental Regulations, Laws and Taxation —The reduction, elimination or inability to monetize government incentives could adversely affect our business, financial condition, future results and cash flows.”

Ormat Systems received “Benefited Enterprise” status under Israel’s Law for Encouragement of Capital Investments, 1959 (the Investment Law), with respect to two of its investment programs through 2011. In January 2011, new legislation amending the Investment Law was enacted. Under the new legislation, a uniform rate of corporate tax will apply to all qualified income of certain industrial companies, as opposed to the previous law’s incentives that are limited to income from a “Benefited Enterprise” during their benefits period. As a result, we now pay a uniform corporate tax rate of 16% with respect to that qualified income. In January 2021, Ormat Systems received an approval from the Israeli Innovation Authority that it owns an "Innovation Promoting Enterprise" and therefore is eligible for a reduced corporate tax rate of 12% on its "Preferred Technological Income" for the tax years 2019 and 2020 (effective tax rate of approximately 13% for 2019 and 2020). The tax benefit of lower effective tax rate is reflected in the 2021 net income.

Information responding to Item 7A is included in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report.

Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO (principal executive officer) and CFO (principal financial officer), as appropriate, to allow for timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

As required by SEC Rule 13a-15(e), we carried out an evaluation, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of our disclosure controls and procedures as of December 31, 2025. Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2025 to provide the reasonable assurance described above.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) of the Exchange Act. Under the supervision and with the participation of our management, including the CEO and the CFO, we carried out an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2025 using the criteria established in “Internal Control-Integrated Framework” (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on that evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2025.

Our internal control over financial reporting as of December 31, 2025 has been audited by Kesselman & Kesselman, Certified Public Accountants (Isr.), an independent registered public accounting firm and a member of PricewaterhouseCoopers International Limited (“PwC”), as stated in their report which is included under “Item 8—Financial Statements.”