ORMAT TECHNOLOGIES, INC. (ORA)

ITEM 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cautionary Note Regarding Forward-Looking Statements

This quarterly report on Form 10-Q includes “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this quarterly report that address activities, events or developments that we expect or anticipate will or may occur in the future, including such matters as our projections of annual revenues, expenses and debt service coverage with respect to our debt securities, future capital expenditures, business strategy, competitive strengths, goals, development or operation of generation assets, market and industry developments and the growth of our business and operations, are forward-looking statements. When used in this quarterly report on Form 10-Q, the words “may”, “will”, “could”, “should”, “expects”, “plans”, “anticipates”, “believes”, “estimates”, “predicts”, “projects”, “potential”, “contemplate”, or “target” or the negative of these terms or other comparable terminology are intended to identify forward-looking statements, although not all forward-looking statements contain such words or expressions. The forward-looking statements in this quarterly report are primarily located in the material set forth under the headings “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, “Risk Factors”, and “Notes to Condensed Consolidated Financial Statements”, but are found in other locations as well. These forward-looking statements generally relate to our plans, objectives and expectations for future operations and are based upon management’s current estimates and projections of future results or trends. Although we believe that our plans and objectives reflected in or suggested by these forward-looking statements are reasonable, we may not achieve these plans or objectives. You should read this quarterly report on Form 10-Q completely and with the understanding that actual future results and developments may be materially different from what we expect attributable to a number of risks and uncertainties, many of which are beyond our control.

These forward-looking statements are made only as of the date hereof, and, except as legally required, we undertake no obligation to update or revise the forward-looking statements, whether as a result of new information, future events or otherwise.

During the period covered by this quarterly report on Form 10-Q, there have been no material changes in our risk factors previously disclosed in our 2025 Annual Report. A summary of the risks that may cause actual results to differ from our expectations include, but are not limited to the following:

Risks Related to the Company’s Business and Operation

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

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

•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 may not achieve its goal of enhancing shareholder value.

•Changes in U.S. and foreign government policy, including the imposition of or increases in tariffs and changes to existing trade agreements, could have a material adverse effect on global economic conditions and our business, results of operations, prospects and financial condition.

•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, volatility in merchant prices and competition.

•Our investments in 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.

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

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

•Political, economic and other conditions in the emerging economies where we operate, including Israel, may subject us to greater risk than in the developed U.S. economy.

•Conditions in and around Israel (including conflicts involving Iran and its proxies) where much of our senior management and our main Product segment production and manufacturing facilities are located, may adversely

27

affect our operations and may limit our ability to produce and sell our products, and may limit our ability to support our operations.

•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.

•Our business development activities may not be successful and our projects under construction or facilities undergoing enhancement and repowering may be delayed due to permitting, regulatory, interconnection and other factors.

•Our future growth depends, in part, on the successful enhancement of a number of our existing facilities.

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

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

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

•We could be impacted by regulatory and other responses to climate change.

•We may not be able to successfully complete acquisitions, and we may not be able to successfully integrate, or realize anticipated synergies from, companies that we have acquired and may acquire in the future.

•Competition for power purchase agreements, development sites, interconnection capacity, and skilled personnel may adversely affect our ability to grow our business or maintain favorable contract terms.

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

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

•We may experience a cyber-incident, cyber security breach, severe natural event or physical attack on our operational networks and information technology systems.

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.

•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.

•If any of our domestic power plants lose their current Qualifying Facility status under the U.S. Public Utility Regulatory Policies Act of 1978 (“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.

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

•Our operations are primarily conducted through our subsidiaries, which are separate legal entities, and our ability to generate 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.

•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, increased costs and delays in construction (as well as fines or penalties that may be imposed upon us in the event of non-compliance with such laws or regulations).

•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.

•U.S. federal, state and foreign country income tax reform could adversely affect us.

28

•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.

Risks Related to Economic and Financial Conditions

•We may be unable to obtain the financing we need on favorable terms to pursue our growth strategy and any future financing we receive may be less favorable to us than our current financing arrangements.

•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.

•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 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.

•If our project subsidiaries default on their obligations under debt or lease financing arrangements, we may be required to make payments to the relevant debt holders, and if the collateral is foreclosed upon, we may lose certain of our power plants.

•We may experience fluctuations in the costs of construction, raw materials, commodities and drilling.

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

•We are exposed to various credit risks.

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

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.

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

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.

•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 following discussion and analysis of our financial condition and results of operations should be read together with our condensed consolidated financial statements and related notes included elsewhere in this quarterly repor

[Excerpt truncated for page length; source filing is linked above.]

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

72

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

73

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

74

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.

Product Segment

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

75

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:

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:

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.

Product Segment

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

77

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.

Product Segment

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

78

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.

79

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.

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 and at 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

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

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

83

$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.

Product Segment

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

84

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.

85

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.

86

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

87

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.

88

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

(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:

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

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

90

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:

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,

91

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 and at 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.

92

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:

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.

93

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:

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

95

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 :

(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

96

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.