ORA

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 Systems (BESS) may be negatively affected by a number of factors, including major change in battery technology, 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 risk. •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 30 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 Product 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. 31 •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 report and the “Risk Factors” section of our 2025 Annual Report on Form 10-K for the year ended December 31, 2025 and any updates contained herein as well as those set forth in our reports and other filings made with the SEC. 32 General Overview We are a leading vertically integrated company primarily engaged in the geothermal power business. We leverage our core capabilities, proprietary technologies, and global presence to expand our activities in conventional geothermal development, recovered energy generation and emerging geothermal technologies, including piloting of new EGS technologies. In addition, we are expanding into different complementary energy solutions, including stand-alone utility scale energy storage services and solar PV generation (including hybrid geothermal and solar PV as well as solar plus energy storage). Our objective is to become a leading global provider of renewable energy and to help mitigate climate change by providing reliable base-load and flexible alternatives to carbon-intensive energy sources. To support this objective, we have adopted a strategic plan focused on several key initiatives to expand our business, including advancing EGS through collaborations and pilot projects, diversifying our renewable energy offerings, and leveraging our operational expertise to drive long-term growth. We currently conduct our business activities in three business segments: •Electricity Segment. In the Electricity segment, we develop, build, own and operate geothermal, solar PV and recovered energy-based power plants in the United States and geothermal power plants in other countries around the world and sell the electricity they generate. In the three and six months ended June 30, 2026, we derived 70.3% and 71.4%, respectively, of our Electricity segment revenues from our operations in the United States and 29.7% and 28.6%, respectively, from the rest of the world. •Product Segment. In the Product segment, we design, manufacture and sell equipment for geothermal and recovered energy-based electricity generation and provide services relating to the engineering, procurement and construction of geothermal and recovered energy-based power plants. In the three and six months ended June 30, 2026, we derived 5.8% and 2.1%, respectively, of our Product segment revenues from our operations in the United States and 94.2% and 97.9%, respectively, from the rest of the world. •Energy Storage Segment. In the Energy Storage segment, we own and operate grid connected, stand alone In Front of the Meter BESS facilities, which provide capacity, energy and/or ancillary services directly to the electric grid. We operate our facilities in three main areas in the U.S., California, Texas and the East Coast (mainly in the PJM market) and generate our revenues mainly from the sale of ancillary services in the merchant market and /or tolling agreements and RA contracts. In the three and six months ended June 30, 2026, we derived all of our Energy Storage segment revenues from our operations in the United States. Our current generating portfolio of approximately 1.8 GW includes geothermal power plants in the United States, Kenya, Guatemala, Honduras, Guadeloupe and Indonesia, as well as energy storage facilities, recovered energy generation and solar PV power plants in the United States. Recent Developments The most significant developments in our Company and business since January 1, 2026 are described below. •On July 31, 2026, we successfully commenced commercial operations of our 10MW Dominica geothermal power in the Commonwealth of Dominica. The project operates under a 25-year power purchase agreement with Dominica Electricity Services Ltd. (“DOMLEC”) and delivers reliable, baseload renewable electricity to the local national grid. •In August 2026, we decided to move forward with the development of the 100MW/400MWh Daneli project in California. The project has a full tolling agreement in place with Clean Power Alliance and is expected to come online by the end of 2028. •In June 2026, we announced the Ormega100, a new surface power generation unit engineered to deliver higher output than currently available binary solutions. The Ormega100 is expected to accelerate our opportunity to commercialize and scale our Enhanced Geothermal System (EGS) developments, connecting subsurface development with surface power generation. The Ormega100 is engineered for the high temperatures required in EGS environments, delivering 100 MW of output in a single autonomous unit. •In April 2026, we signed a long-term Power Purchase Agreement (“PPA”) with NV Energy for the Jersey Valley solar plus storage project, to be located in Lander County, Nevada, subject to Nevada PUC approval. The Jersey Valley project is expected to include approximately 67 MW of solar generation capacity paired with 67 MW / 268 MWh of battery energy storage. The project is expected to achieve commercial operation late in 2027 or early 2028. All output from the project is planned to be sold under the long-term, fixed-price PPA, supporting NV Energy’s clean energy objectives while providing Ormat with predictable, long-term contracted revenues. 33 •In March 2026, we closed a private offering of $1.0 billion aggregate principal amount of convertible senior notes. The offering consists of $825 million aggregate principal amount of 1.50% Series A Convertible Senior Notes due 2031 (the “Series A Notes”) and $175 million aggregate principal amount of 0.00% Series B Convertible Senior Notes due 2031 (the “Series B Notes” and, together with the Series A Notes, the “2031 Convertible Notes”). The 2031 Convertible Notes were sold to persons reasonably believed to be qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”).The Series A Notes will bear interest at a rate of 1.50% per year, payable semi-annually in arrears, and the Series B Notes will not bear regular interest. Both series of 2031 Convertible Notes will mature on March 15, 2031, unless earlier converted, redeemed or repurchased in accordance with their terms. Holders of the Series B Notes will have the right to require the Company to repurchase all or a portion of their 2031 Convertible Notes on March 15, 2027, at a repurchase price equal to 100% of the principal amount, plus any accrued and unpaid special interest, if any. The initial conversion price for both series reflects a premium of 30% over the Company’s common stock price at the time of pricing. •In March 2026, we commenced commercial operations of the Shirk energy storage facility, an 80MW/320MWh Battery Energy Storage System (BESS) located in Visalia, California. The Shirk energy storage facility secures capacity under a 15-year Resource Adequacy Purchase and Sale Agreement (RA Agreement) with the City of Riverside, supporting grid reliability and helping meet California’s growing demand for flexible energy resources. The Shirk project qualifies for a 40% Investment Tax Credit (ITC), the tax benefits of which the Company monetized as part of the hybrid tax equity partnership with Morgan Stanley Renewables, Inc. that the Company announced in May 2025. This partnership supports the funding and optimization of the Company’s growing energy storage portfolio. •In March 2026, we announced the signing and approval of amendments to the existing power purchase agreements (PPAs) with Central Coast Community Energy (3CE) and Silicon Valley Clean Energy (SVCE) for a portion of the output from the 35MW Casa Diablo-IV (CD4) geothermal power plant, part of our Mammoth geothermal complex in California. The amended agreements cover a total of 15MW of contracted capacity. The remaining output from the CD4 facility is sold to the Southern California Public Power Authority (SCPPA). The amended agreements extend the original PPAs, which were signed in 2022 and scheduled to expire in 2032, by five additional years through 2037. We believe the execution of these contracts is in line with the Company’s “blend-and-extend” strategy, aimed at proactively re-contracting existing agreements ahead of expiration while securing improved, demand-driven economics. •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 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 Renewables USA LLC for total cash consideration of $79.3 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 34 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 rights 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. 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 trends, factors and uncertainties discussed in our 2025 Annual Report under “Part II - Item 7 – Management Discussion and Analysis of Financial Condition and Results of Operation”, in addition to the information set forth in this quarterly report. These trends, factors and uncertainties are, from time to time, also subject to market cycles. Revenues For the six months ended June 30, 2026, 94.4% of our Electricity segment revenues were derived from PPAs with fixed energy rates, which are not affected by fluctuations in energy commodity prices. We have a variable price PPA in Hawaii, which provides for payments based on the local utilities’ avoided cost, which 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 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. 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 2027. To comply with obligations under their respective PPAs, certain of our project subsidiaries are structured as special purpose, bankruptcy remote entities and their assets and liabilities are ring-fenced. Such assets are not generally available to pay our debt, other than debt at the respective project subsidiary level. However, these project subsidiaries are allowed to pay dividends and make distributions of cash flows generated by their assets to us, subject in some cases to restrictions in debt instruments, as described below. Electricity segment revenues are also subject to seasonal variations and are affected by higher-than-average ambient temperatures, as described below under “Seasonality”. These variations became severe in recent years due to extreme weather events and in some cases cannot be forecasted. 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, or as related to the Dominica project, under a BOT agreement with the Commonwealth of Dominica. Product segment revenues vary from period to period because of the timing of our receipt of purchase orders and the progress of our equipment manufacturing and execution of the relevant project. 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. 35 The following table sets forth a breakdown of our revenues for the periods indicated: Revenue % of Revenues for Period Indicated Three Months Ended June 30, Three Months Ended June 30, 2026 2025 Increase (Decrease) 2026 2025 (Dollars in thousands) Revenues: Electricity $ 169,253 $ 159,912 $ 9,341 5.8 % 65.4 % 68.3 % Product 46,739 59,612 (12,873) (21.6) 18.1 25.5 Energy storage 42,772 14,494 28,278 195.1 16.5 6.2 Total $ 258,764 $ 234,018 $ 24,746 10.6 % 100.0 % 100.0 % Revenue % of Revenues for Period Indicated Six Months Ended June 30, Six Months Ended June 30, 2026 2025 Increase (Decrease) 2026 2025 (Dollars in thousands) Revenues: Electricity $ 350,856 $ 340,153 $ 10,703 3.1 % 52.9 % 73.3 % Product 224,122 91,381 132,741 145.3 33.8 19.7 Energy storage 87,697 32,246 55,451 172.0 13.2 7.0 Total $ 662,675 $ 463,780 $ 198,895 42.9 % 100.0 % 100.0 % 36 The following table sets forth the geographic breakdown of the revenues attributable to our Electricity, Product and Energy Storage segments for the periods indicated: Revenue % of Revenues for Period Indicated Three Months Ended June 30, Three Months Ended June 30, 2026 2025 Increase (Decrease) 2026 2025 Electricity Segment: (Dollars in thousands) United States $ 118,963 $ 111,417 $ 7,546 6.8 % 70.3 % 69.7 % Foreign 50,290 48,495 1,795 3.7 29.7 30.3 Total $ 169,253 $ 159,912 $ 9,341 5.8 % 100.0 % 100.0 % Product Segment: United States $ 2,723 $ 3,523 $ (800) (22.7) % 5.8 % 5.9 % Foreign 44,016 56,089 (12,073) (21.5) 94.2 94.1 Total $ 46,739 $ 59,612 $ (12,873) (21.6) % 100.0 % 100.0 % Energy Storage Segment: United States $ 42,772 $ 14,494 $ 28,278 195.1 % 100.0 % 100.0 % Total $ 42,772 $ 14,494 $ 28,278 195.1 % 100.0 % 100.0 % Revenue % of Revenues for Period Indicated Six Months Ended June 30, Six Months Ended June 30, 2026 2025 Increase (Decrease) 2026 2025 (Dollars in thousands) Electricity Segment: United States $ 250,560 $ 245,631 $ 4,929 2.0 % 71.4 % 72.2 % Foreign 100,296 94,522 5,774 6.1 28.6 27.8 Total $ 350,856 $ 340,153 $ 10,703 3.1 % 100.0 % 100.0 % Product Segment: United States $ 4,775 $ 6,762 $ (1,987) (29.4) % 2.1 % 7.4 % Foreign 219,347 84,619 134,728 159.2 97.9 92.6 Total $ 224,122 $ 91,381 $ 132,741 145.3 % 100.0 % 100.0 % Energy Storage Segment: United States $ 87,697 $ 32,246 $ 55,451 172.0 % 100.0 % 100.0 % Total $ 87,697 $ 32,246 $ 55,451 172.0 % 100.0 % 100.0 % In the six months ended June 30, 2026 and 2025, 48.2% and 38.6% of our total revenues, respectively, were derived from foreign locations, and 36.4% and 44.7% for the three months ended June 30, 2026 and 2025, respectively. Our foreign operations had higher Electricity gross margins than our U.S. operations in each of those periods. A substantial portion of 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. 37 Electricity Segment. Our Electricity segment domestic revenues were approximately 71.4% and 72.2% of our total Electricity segment revenues for the six months ended June 30, 2026 and 2025, respectively, and 70.3% and 69.7% for the three months ended June 30, 2026 and 2025, respectively. Our Electricity segment foreign revenues were approximately 28.6% and 27.8% of our total Electricity segment revenues for the six months ended June 30, 2026 and 2025, respectively, and 29.7% and 30.3% for the three months ended June 30, 2026 and 2025, 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, and Honduras, which favorably impact payroll, maintenance expenses and other items. Our power plants in those 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 the six months ended June 30, 2026 and 2025, our foreign operations of the segment accounted for 28.5% and 40.1%, respectively, of our total gross profits, 39.3% and 49.2%, respectively, of our net income (assuming the majority of corporate operating expenses and financing are recorded under our domestic jurisdiction), and 27.7% and 28.6%, respectively, of our EBITDA. Product Segment. Our Product segment foreign revenues were approximately 97.9% and 92.6% of our total Product segment revenues for the six months ended June 30, 2026 and 2025, respectively. Energy Storage Segment. Our Energy Storage segment domestic revenues were 100% of our total Energy Storage segment revenues for each of the three and six months ended June 30, 2026 and 2025. 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 Energy 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. In addition, we see in the last two years higher revenues during the first quarter and fourth quarter due to high merchant pricing at PJM market, although during 2026 we experienced high merchant prices in the second quarter as well. Breakdown of Cost of Revenues The principal cost of revenues attributable to our three segments are discussed in our 2025 Annual Report under “Part II - Item 7 – Management Discussion and Analysis of Financial Condition and Results of Operations.” Critical Accounting Estimates and Assumptions A comprehensive discussion of our critical accounting estimates and assumptions is included in our 2025 Annual Report under “Part II, Item 7 — Management Discussion and Analysis of Financial Condition and Results of Operations.” New Accounting Pronouncements See Note 2 to our condensed consolidated financial statements set forth in Item 1 of this quarterly report for information regarding new accounting pronouncements. 38 Results of Operations Our historical operating results in U.S. dollars and as a percentage of total revenues are presented below for each of the periods indicated. Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (Dollars in thousands, except per share data) (Dollars in thousands, except per share data) Statements of Operations Historical Data: Revenues: Electricity $ 169,253 $ 159,912 $ 350,856 $ 340,153 Product 46,739 59,612 224,122 91,381 Energy storage 42,772 14,494 87,697 32,246 Total Revenues 258,764 234,018 662,675 463,780 Cost of revenues: Electricity 129,121 121,236 254,865 241,069 Product 42,217 43,118 181,626 67,802 Energy storage 18,728 12,769 37,117 25,087 Total cost of revenues 190,066 177,123 473,608 333,958 Gross profit Electricity 40,132 38,676 95,991 99,084 Product 4,522 16,494 42,496 23,579 Energy storage 24,044 1,725 50,580 7,159 Total gross profit 68,698 56,895 189,067 129,822 Operating expenses: Research and development expenses 1,501 1,439 2,633 3,981 Selling and marketing expenses 5,968 4,370 11,545 8,542 General and administrative expenses 21,104 19,786 48,440 37,695 Other operating income (1,000) (4,269) (5,125) (7,394) Impairment of long-lived assets 316 — 8,428 — Write-off of unsuccessful exploration and storage activities 6,611 251 8,693 767 Operating income 34,198 35,318 114,453 86,231 Other income (expense): Interest income 7,071 1,929 8,501 3,242 Interest expense, net (43,938) (36,682) (88,931) (71,155) Derivatives and foreign currency transaction gains (losses) 274 5,068 (1,263) 7,128 Income attributable to sale of tax benefits 16,553 16,251 33,174 33,822 Other non-operating income (expense), net 3,001 76 (20,144) 298 Income from operations before income tax and equity in earnings (losses) of investees 17,159 21,960 45,790 59,566 Income tax (provision) benefit 9,666 5,466 25,136 9,261 Equity in earnings (losses) of investees (811) 773 (299) 406 Net income 26,014 28,199 70,627 69,233 Net income (loss) attributable to noncontrolling interest 1,072 (153) 527 (825) Net income attributable to the Company's stockholders $ 27,086 $ 28,046 $ 71,154 $ 68,408 Earnings per share attributable to the Company's stockholders: 39 Basic: $ 0.44 $ 0.46 $ 1.16 $ 1.13 Diluted: $ 0.43 $ 0.46 $ 1.14 $ 1.12 Weighted average number of shares used in computation of earnings per share attributable to the Company's stockholders: Basic 61,484 60,689 61,225 60,624 Diluted 62,534 61,019 62,567 60,973 Operating results as a percentage of total revenues: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 Statements of Operations Data: Revenues: Electricity 65.4 % 68.3 % 52.9 % 73.3 % Product 18.1 25.5 33.8 19.7 Energy storage 16.5 6.2 13.2 7.0 Total Revenues 100.0 100.0 100.0 100.0 Cost of revenues: Electricity 76.3 75.8 72.6 70.9 Product 90.3 72.3 81.0 74.2 Energy storage 43.8 88.1 42.3 77.8 Total cost of revenues 73.5 75.7 71.5 72.0 Gross profit Electricity 23.7 24.2 27.4 29.1 Product 9.7 27.7 19.0 25.8 Energy storage 56.2 11.9 57.7 22.2 Total gross profit 26.5 24.3 28.5 28.0 Operating expenses: Research and development expenses 0.6 0.6 0.4 0.9 Selling and marketing expenses 2.3 1.9 1.7 1.8 General and administrative expenses 8.2 8.5 7.3 8.1 Other operating income (0.4) (1.8) (0.8) (1.6) Impairment of long-lived assets 0.1 — 1.3 — Write-off of unsuccessful exploration and storage activities 2.6 0.1 1.3 0.2 Operating income 13.2 15.1 17.3 18.6 Other income (expense): Interest income 2.7 0.8 1.3 0.7 Interest expense, net (17.0) (15.7) (13.4) (15.3) Derivatives and foreign currency transaction gains (losses) 0.1 2.2 (0.2) 1.5 Income attributable to sale of tax benefits 6.4 6.9 5.0 7.3 Other non-operating income (expense), net 1.2 — (3.0) 0.1 Income from operations before income tax and equity in earnings (losses) of investees 6.6 9.4 6.9 12.8 Income tax (provision) benefit 3.7 2.3 3.8 2.0 Equity in earnings (losses) of investees (0.3) 0.3 0.0 0.1 Net income 10.1 12.0 10.7 14.9 Net income (loss) attributable to noncontrolling interest 0.4 (0.1) 0.1 (0.2) Net income attributable to the Company's stockholders 10.5 % 12.0 % 10.7 % 14.8 % 40 Comparison of the Three Months Ended June 30, 2026 to the Three Months Ended June 30, 2025 Total Revenues The table below compares revenues for the three months ended June 30, 2026 to the three months ended June 30, 2025. Three Months Ended June 30, 2026 2025 Change (Dollars in millions) Electricity segment $ 169.3 $ 159.9 5.8 % Product segment 46.7 59.6 (21.6) Energy Storage segment 42.8 14.5 195.1 Total revenues $ 258.8 $ 234.0 10.6 % Electricity Segment Revenues attributable to our Electricity segment for the three months ended June 30, 2026 were $169.3 million, compared to $159.9 million for the three months ended June 30, 2025. This increase of $9.3 million was mainly attributable to: (i) $2.6 million related to the Blue Mountain power plant which was purchased in June 2025; (ii) $2.5 million related to the Olkaria power plant primarily due to an increase in generation resulting from a successful drilling of additional wells as well as lower curtailments; (iii) $3.0 million related to the Puna power plant primarily related to temporary reduction in power generation in the previous year that was caused by wellfield issues, as well as to higher avoided cost prices during the second quarter of 2026 compared to the same period in 2025; and (iv) $4.2 million related to the McGinness Hills complex, Dixie Valley and the Tungsten power plant, primarily as a result of curtailments from the transmission system operator during the second quarter of the prior year. This increase was partially offset by smaller amounts of decreases in a number of power plants across our fleet. Power generation in our power plants increased by 3.0% from 1,747,022 MWh in the three months ended June 30, 2025 to 1,800,289 MWh in the three months ended June 30, 2026. Product Segment Revenues attributable to our Product segment for the three months ended June 30, 2026 were $46.7 million, compared to $59.6 million for the three months ended June 30, 2025. This decrease of $12.9 million, or 21.6%, is primarily related to the progress in our other projects and timing of when revenues are recognized during the period. During the three months ended June 30, 2026, Product revenues included projects primarily in New Zealand and Turkey, and during the three months ended June 30, 2025, projects in New Zealand and Dominica. Energy Storage Segment Revenues attributable to our Energy Storage segment for the three months ended June 30, 2026 were $42.8 million compared to $14.5 million for the three months ended June 30, 2025. This increase of $28.3 million is primarily related to higher energy rates at PJM storage facilities in the three months ended June 30, 2026, compared to the same period in the previous year, and related to new energy storage facilities such as Arrowleaf and Lower Rio which commenced commercial operations in December 2025 and September 2025, respectively, Hoku, which was acquired in January 2026, and Shirk which commenced commercial operations in March 2026, which contributed $7.7 million to revenues, combined. 41 Total Cost of Revenues The table below compares cost of revenues for the three months ended June 30, 2026 to the three months ended June 30, 2025. Three Months Ended June 30, 2026 2025 Change (Dollars in millions) Electricity segment $ 129.1 $ 121.2 6.5 % Product segment 42.2 43.1 (2.1) Energy Storage segment 18.7 12.8 46.7 Total cost of revenues $ 190.1 $ 177.1 7.3 % Electricity Segment Total cost of revenues attributable to our Electricity segment for the three months ended June 30, 2026 was $129.1 million, compared to $121.2 million for the three months ended June 30, 2025, which represents an increase of $7.9 million, or 6.5%. This increase is primarily attributable to $1.6 million related to the Blue Mountain power plant which was purchased in June 2025, $2.5 million increase in power plant depreciation expenses as a result of our investment in our power plants, and to other smaller amount increases in certain other power plants. Our total Electricity segment cost of revenues for the three months ended June 30, 2026 was 76.3% of Electricity segment revenues, compared to 75.8% for the three months ended June 30, 2025. The cost of revenues attributable to our international power plants for the three months ended June 30, 2026 was 18.3% of our total Electricity segment cost of revenues for this period compared to 18.0% for the same period in the prior year. Product Segment Total cost of revenues attributable to our Product segment for the three months ended June 30, 2026 was $42.2 million, compared to $43.1 million for the three months ended June 30, 2025, which represented a 2.1% decrease. This decrease is primarily attributable to the decrease in Product segment revenues as well as to lower profitability of projects included in the three months ended June 30, 2026 compared to those included in the three months ended June 30, 2025. As a percentage of total Product segment revenues, total cost of revenues attributable to our Product segment for the three months ended June 30, 2026, and 2025, was 90.3% and 72.3%, respectively, which results from the different profitability of the different projects included in each period. Energy Storage Segment Cost of revenues attributable to our Energy Storage segment for the three months ended June 30, 2026 was $18.7 million compared to $12.8 million for the three months ended June 30, 2025. This increase of $6.0 million includes an increase of $3.6 million in depreciation and amortization expenses, and is primarily related to the new energy storage facilities such as Arrowleaf and Lower Rio which commenced commercial operations in December 2025 and September 2025, respectively, Hoku, which was acquired in January 2026, and Shirk, which commenced commercial operations in March 2026, which contributed $2.4 million to cost of revenues, combined. Research and Development Expenses, Net Research and development expenses for the three months ended June 30, 2026 were $1.5 million, compared to $1.4 million for the three months ended June 30, 2025. The increase in research and development expenses, net, is primarily related to the timing of when we allocate resources to research and development projects. Selling and Marketing Expenses Selling and marketing expenses for the three months ended June 30, 2026 were $6.0 million compared to $4.4 million for the three months ended June 30, 2025. Selling and marketing expenses for the three months ended June 30, 2026 and 2025 constituted 2.3% and 1.9% of total revenues, respectively. The increase in selling and marketing expenses is primarily related to the timing of recording the related expenses. 42 General and Administrative Expenses General and administrative expenses for the three months ended June 30, 2026 were $21.1 million compared to $19.8 million for the three months ended June 30, 2025. General and administrative expenses for the three months ended June 30, 2026 and 2025 constituted 8.2% and 8.5% of total revenues, respectively. Other Operating Income Other operating income for the three months ended June 30, 2026 was $1.0 million compared to $4.3 million for the three months ended June 30, 2025. Other operating income for the three months ended June 30, 2025 primarily represents the non-refundable portion of the recovery of damages received from a third-party battery systems supplier as part of a previously-disclosed settlement agreement entered into in August 2024, for which contingency conditions have been met. Other operating income for the three months ended June 30, 2026 represents income recognition from services provided to Sage. Impairment of Long-Lived Assets Impairment of long-lived assets for the three months ended June 30, 2026 was $0.3 million compared to none for the three months ended June 30, 2025. Write-off of Unsuccessful Exploration and Storage Activities Write-off of unsuccessful exploration and storage activities for the three months ended June 30, 2026 was $6.6 million compared to $0.3 million for the three months ended June 30, 2025. These write-offs are primarily related to storage projects that the Company decided to no longer pursue. Interest Income Interest income for the three months ended June 30, 2026 was $7.1 million, compared to $1.9 million for the three months ended June 30, 2025. Interest income is primarily related to interest earned on cash and cash equivalents held by the Company during the period. The increase in interest income is attributable to higher cash deposits, period over period, originated from the proceeds of 2031 Convertible Notes. Interest Expense, Net Interest expense, net for the three months ended June 30, 2026 was $43.9 million, compared to $36.7 million for the three months ended June 30, 2025. This increase of $7.3 million was primarily attributable to interest expense relating to issuance of the 2031 Convertible Notes in March 2026, and loan agreements and tax monetization transactions entered into subsequently to the second quarter of 2025. This increase was partially offset by lower interest expenses on other existing loans as a result of their scheduled payments. Derivatives and Foreign Currency Transaction Gains (Losses) Derivatives and foreign currency transaction gains and losses for the three months ended June 30, 2026 was a gain of $0.3 million, compared to a gain of $5.1 million for the three months ended June 30, 2025. Derivatives and foreign currency transaction gains and losses primarily include gain and losses from foreign currency forward and option 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 three months ended June 30, 2026 was $16.6 million, compared to $16.3 million for the three months ended June 30, 2025. This income primarily represents the value of PTCs and taxable income or loss generated by certain of our power plants which are allocated to investors under tax equity transactions, and to income related to the expected sale of transferable PTCs under the existing IRA regulations. Other Non-Operating Income (Expense), Net Other non-operating income (expense), net for the three months ended June 30, 2026 was an income of $3.0 million, compared to an income of $0.1 million for the three months ended June 30, 2025. Other non-operating income for the three months ended June 30, 2026 is primarily related to remeasurement of our SAFE investment in an unconsolidated investee under the measurement alternative accounting. Income Taxes Income tax benefit for the three months ended June 30, 2026 was $9.7 million compared to income tax benefit of $5.5 million for the three months ended June 30, 2025. This change primarily relates to the generation of additional investment tax 43 credits, the partial reversal of the provision for uncertain tax positions, and the jurisdictional mix of earnings at differing tax rate. Our effective tax rate for the three months ended June 30, 2026 and 2025, was (56.3)% and (24.9)%, respectively. The effective rate differs from the federal statutory rate of 21% primarily due to the generation of investment tax credits. Equity in Earnings (Losses) of Investees, Net Equity in earnings of investees, net for the three months ended June 30, 2026 was a loss of $0.8 million, compared to earnings of $0.8 million for the three months ended June 30, 2025. Equity in earnings (losses) of investees, net is derived from our 12.75% share in the earnings or losses in the Sarulla Consortium (“Sarulla”) and our 49% share in the earnings or losses in the Ijen geothermal project. Net Income Attributable to the Company’s Stockholders Net income attributable to the Company’s stockholders for the three months ended June 30, 2026 was $27.1 million, compared to $28.0 million for the three months ended June 30, 2025, which represents a decrease of $1.0 million. This decrease is attributable to a decrease of $2.2 million in net income which was affected by the explanations described above, and a decrease of $1.2 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. Comparison of the Six Months Ended June 30, 2026 to the Six Months Ended June 30, 2025 Total Revenues The table below compares revenues for the six months ended June 30, 2026 to the six months ended June 30, 2025. Six Months Ended June 30, 2026 2025 Change Segment Revenues: (Dollars in millions) Electricity segment $ 350.9 $ 340.2 3.1 % Product segment 224.1 91.4 145.3 Energy Storage segment 87.7 32.2 172.0 Total revenues $ 662.7 $ 463.8 42.9 % Electricity Segment Revenues attributable to our Electricity segment for the six months ended June 30, 2026, were $350.9 million, compared to $340.2 million for the six months ended June 30, 2025. The increase of $10.7 million in our Electricity segment revenues was mainly attributable to: (i) $5.8 million related to the Blue Mountain power plant which was purchased in June 2025; (ii) $6.9 million related to the Olkaria power plant, primarily due to an increase in generation resulting from a successful drilling of additional wells and better resource utilization; and (iii) $3.7 million related to the Dixie Valley power plant primarily as a result of reduction in curtailments from SCE. This increase was partially offset by a $3.7 million decrease in revenues related to the Heber complex due to planned maintenance work that took place in 2025. In addition, unfavorable ambient temperatures in the first half of 2026 resulted in a decline in generation and, consequently, in revenues across our power plant fleet. Power generation in our power plants increased by 2.0% from 3,756,619 MWh in the six months ended June 30, 2025 to 3,833,361 MWh in the six months ended June 30, 2026. Product Segment Revenues attributable to our Product segment for the six months ended June 30, 2026 were $224.1 million, compared to $91.4 million for the six months ended June 30, 2025. This increase of $132.7 million, or 145.3%, is primarily related to: (i) the sale of the TOPP2 power plant in New Zealand for which revenues of $105.1 million were recognized in the first quarter of 2026 upon meeting all revenue recognition criteria during that quarter; and (ii) the progress in our projects which results in the timing of when revenues are recognized. During the six months ended June 30, 2026, Product revenues included projects primarily in New Zealand and Turkey, and during the six months ended June 30, 2025, Product revenues included projects primarily in New Zealand and Dominica. 44 Energy Storage Segment Revenues attributable to our Energy Storage segment for the six months ended June 30, 2026 were $87.7 million compared to $32.2 million for the six months ended June 30, 2025. The increase of $55.5 million is primarily related to higher energy rates at PJM storage facilities in the six months ended June 30, 2026, compared to the same period in the previous year and to the new energy storage facilities such as Arrowleaf and Lower Rio which commenced commercial operations in December 2025 and September 2025, respectively, Hoku, which was acquired in January 2026, and Shirk, which commenced commercial operations in March 2026, which contributed $11.9 million to revenues, combined. Total Cost of Revenues The table below compares cost of revenues for the six months ended June 30, 2026 to the six months ended June 30, 2025. Six Months Ended June 30, 2026 2025 Change Segment Cost of Revenues: (Dollars in millions) Electricity segment $ 254.9 $ 241.1 5.7 % Product segment 181.6 67.8 167.9 Energy Storage segment 37.1 25.1 48.0 Total cost of revenues $ 473.6 $ 334.0 41.8 % Electricity Segment Total cost of revenues attributable to our Electricity segment for the six months ended June 30, 2026 was $254.9 million, compared to $241.1 million for the six months ended June 30, 2025, which represents an increase of $13.8 million, or 5.7%. This increase is primarily attributable to (i) an increase in power plant depreciation expenses of $4.5 million, as a result of our investments in our power plants; (ii) $3.6 million related to the Blue Mountain power plant which was purchased in June 2025; (iii) $2.6 million related to the Olkaria power plant, primarily as a result of the increase in generation described above; and (iv) additional increases in lower amounts in our other power plants. Our total Electricity segment cost of revenues for the six months ended June 30, 2026 was 72.6% of Electricity revenues, compared to 70.9% for the six months ended June 30, 2025. The cost of revenues attributable to our international power plants for the six months ended June 30, 2026 was 18.2% of our total Electricity segment cost of revenues for this period, compared to 17.6% for the same period in the prior year. Product Segment Total cost of revenues attributable to our Product segment for the six months ended June 30, 2026 was $181.6 million, compared to $67.8 million for the six months ended June 30, 2025, which represented a 167.9% increase. This increase was primarily attributable to the increase in Product segment revenues, including the sale of the TOPP2 power plant, as discussed above. As a percentage of total Product segment revenues, our total cost of revenues attributable to our Product segment for the six months ended June 30, 2026, and 2025, was 81.0% and 74.2%, respectively, which results from the different profitability of the different projects included in each period. Energy Storage Segment Cost of revenues attributable to our Energy Storage segment for the six months ended June 30, 2026 was $37.1 million compared to $25.1 million for the six months ended June 30, 2025. This increase of $12.0 million includes an increase of $6.0 million in depreciation and amortization expenses, and is primarily related to the new energy storage facilities such as Arrowleaf and Lower Rio which commenced commercial operations in December 2025 and September 2025, respectively, Hoku, which was acquired in January 2026, and Shirk, which commenced commercial operations in March 2026, which contributed $4.6 million to cost of revenues, combined. Research and Development Expenses, Net Research and development expenses for the six months ended June 30, 2026 were $2.6 million, compared to $4.0 million for the six months ended June 30, 2025. The decrease in research and development expenses is mainly attributable to the timing of when we allocate resources to research and development projects. 45 Selling and Marketing Expenses Selling and marketing expenses for the six months ended June 30, 2026 were $11.5 million compared to $8.5 million for the six months ended June 30, 2025. Selling and marketing expenses for the six months ended June 30, 2026 constituted 1.7% of total revenues, compared to 1.8% for the six months ended June 30, 2025. General and Administrative Expenses General and administrative expenses for the six months ended June 30, 2026 were $48.4 million compared to $37.7 million for the six months ended June 30, 2025. The increase of $10.7 million in general and administrative expenses is primarily attributable to: (i) an increase in employee-related costs of $2.5 million, including an increase of $0.7 million of stock-based compensation; (ii) the settlement agreement amount related to the previously-disclosed lawsuit, which was recorded in the first quarter of 2026, compared to $0.9 million related to a different legal settlement which was included in the same period of the previous year; and (iii) timing of cost of services provided, primarily from professional service providers. Other Operating Income Other operating income for the six months ended June 30, 2026 was $5.1 million compared to $7.4 million for the six months ended June 30, 2025. 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 contingency conditions have been met. Other operating income for the six months ended June 30, 2026 also includes income recognition from services provided to Sage. Impairment of Long-Lived Assets Impairment of long-lived assets for the six months ended June 30, 2026 was $8.4 million compared to none for the six months ended June 30, 2025. Impairment of long-lived assets for in 2026 is primarily related to the Pomona 1 battery energy storage facility. During the first quarter of 2026, the Company approved a project to construct the new Pomona 3 storage facility which will replace the existing Pomona 1 storage facility. The Pomona 1 storage facility is scheduled for demolishing in late 2026 to facilitate the construction of the new storage facility. Write-off of Unsuccessful Exploration and Storage Activities Write-off of unsuccessful exploration and storage activities for the six months ended June 30, 2026 was $8.7 million, compared to $0.8 million for the six months ended June 30, 2025. These write-offs are related to accumulated costs of geothermal exploration and storage projects that the Company decided to no longer pursue. Interest Income Interest income for the six months ended June 30, 2026, was $8.5 million, compared to $3.2 million for the six months ended June 30, 2025. Interest income is primarily related to interest earned on cash and cash equivalents held by the Company during the period. The increase in interest income is primarily related to the higher cash deposits, period over period, originated from the proceeds of the 2031 Convertible Notes. Interest Expense, Net Interest expense, net for the six months ended June 30, 2026 was $88.9 million, compared to $71.2 million for the six months ended June 30, 2025. This increase of $17.8 million is primarily attributable to interest expenses relating to loan agreements and tax monetization transactions entered into during, or subsequent to, the six months ended June 30, 2025, including the issuance of the 2031 Convertible Notes in March 2026. This increase was partially offset by 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 and losses for the six months ended June 30, 2026 was a loss of $1.3 million, compared to a gain of $7.1 million for the six months ended June 30, 2025. Derivatives and foreign currency transaction gains and losses primarily includes losses from foreign currency forward and option contracts which were not accounted for as hedge transactions, and the impact of changes in foreign currency exchange rates against the U.S. Dollar. 46 Income Attributable to Sale of Tax Benefits Income attributable to the sale of tax benefits for the six months ended June 30, 2026 was $33.2 million, compared to $33.8 million for the six months ended June 30, 2025. This income primarily represents the value of PTCs and taxable income or loss generated by certain of our power plants which are allocated to investors under tax equity transactions, and to income related to the expected sale of transferable production tax credits under the IRA regulations. Other Non-Operating Income (Expense), Net Other non-operating income (expense), net for the six months ended June 30, 2026 was $(20.1) million, compared to $0.3 million for the six months ended June 30, 2025. Other non-operating income for the six months ended June 30, 2026 is primarily related to the induced conversion expense of $34.4 million resulting from the repurchase of the 2027 Convertible Notes, offset primarily by a bargain purchase gain of $9.6 million related to the purchase transaction of the Hoku storage and solar facility, and to the remeasurement of our SAFE investment in an unconsolidated investee under the measurement alternative accounting. Income Taxes Income tax benefit for the six months ended June 30, 2026 was $25.1 million compared to income tax benefit of $9.3 million for the six months ended June 30, 2025. This change primarily relates to the generation of additional investment tax credits, the change in “Income from operations before income tax and equity in earnings of investees”, and the jurisdictional mix of earnings at differing tax rates. Our effective tax rate for the six months ended June 30, 2026 and 2025, was (54.9)% and (15.5)%, respectively. Equity in Earnings (Losses) of Investees, Net Equity in earnings and losses of investees, net for the six months ended June 30, 2026 was losses of $0.3 million, compared to earnings of $0.4 million for the six months ended June 30, 2025. Equity in earnings and losses of investees, net is mainly derived from our 12.75% share in the earnings or losses in the Sarulla consortium and our 49% share in the earnings or losses from the Ijen geothermal project. The change in equity in earnings of investees is directly related to the changes in net income generated by these investees. Net Income Attributable to the Company’s Stockholders Net income attributable to the Company’s stockholders for the six months ended June 30, 2026 was $71.2 million, compared to $68.4 million for the six months ended June 30, 2025, which represents an increase of $2.7 million. This increase was attributable to the increase of $1.4 million in net income which was affected by the explanations described above, as well as a decrease of $1.4 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 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, private or public offerings and issuances of debt or equity securities, project financing and tax monetization transactions, short term borrowing under our lines of credit, and proceeds from the sale of equity interests in one or more of our projects. We have utilized this cash to develop and construct power plants, fund our acquisitions, pay down existing outstanding indebtedness, and meet our other cash and liquidity needs. As of June 30, 2026, we had access to (i) $513.7 million in cash and cash equivalents, of which $179.8 million is held by our foreign subsidiaries; and (ii) $377.3 million of unused corporate borrowing capacity under existing committed lines for credit and letters of credit with different commercial banks. Our estimated capital needs for the remainder of 2026 include $449.0 million for capital expenditures on new projects under development or construction including energy storage projects, exploration activity and maintenance capital expenditures for our existing projects. In addition, $133.7 million will be needed for long-term debt repayment. 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 transactions). 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. As of June 30, 2026, we continue to maintain our assertion to no longer indefinitely reinvest foreign funds held by our foreign subsidiaries, and have accrued the incremental foreign withholding taxes. Accordingly, during the six months ended 47 June 30, 2026, we included a foreign income tax expense of $0.3 million related to foreign withholding taxes on accumulated earnings of all of our foreign subsidiaries. As further described under Note 1 to the condensed consolidated financial statements, the Company entered into the new indenture agreements during the six months ended June 30, 2026 for the issuance of $1.0 billion of convertible senior notes due March 15, 2031. Letters of Credits Under 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. Credit Agreements Amount Issued Issued and Outstanding as of June 30, 2026 Termination Date (Dollars in millions) 377.3 Committed lines for credit and letters of credit $ 533.0 $ 155.7 October 2026 - June 2028 Committed lines for letters of credit 210.0 86.2 October 2026 - August 2027 Non-committed lines — 35.9 July 2026 - October 2026 Total $ 743.0 $ 277.8 Restrictive Covenants Our obligations under the credit agreements, the loan agreements, and the trust instrument governing the bonds described above, 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, restraints on: (i) creating any floating charge or any permanent pledge, charge or lien over our assets without obtaining the prior written approval of the lender; (ii) guaranteeing the liabilities of any third party without obtaining the prior written approval of the lender; and (iii) selling, assigning, transferring, conveying or disposing of all or substantially all of our assets, or a change of control in our ownership structure. Some of the credit agreements, the term loan agreements, and the trust instrument contain cross-default provisions with respect to other material indebtedness owed by us to any third party. In some cases, 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 June 30, 2026: (i) total equity was $2,734.1 million and the actual equity to total assets ratio was 40.3% and (ii) the 12-month debt, net of cash, cash equivalents, to Adjusted EBITDA ratio was 4.26. During the six months ended June 30, 2026, we distributed interim dividends in an aggregate amount of $14.7 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 and the trust instrument (except as described below), 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 June 30, 2026, 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 June 30, 2026, the amount restricted for distribution by this subsidiary was $1.3 million. Additionally, as of June 30, 2026, we were not in compliance with the OFC 2 Senior Secured Notes due to a certain administrative noncompliance issue under the loan agreement. Debt service payments are made regularly and financial covenants are in compliance. We are currently discussing with the lender on finalizing a waiver to rectify the issue. As of June 30, 2026, the amount restricted for distribution due to this matter was $33.2 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 June 30, 2026. 48 Future minimum payments Future minimum cash payments under long-term obligations (including long-term debt, lease obligations and financing liability), as of June 30, 2026, are as follows: (Dollars in thousands) Year ending December 31: 2026 $ 153,209 2027 525,026 2028 364,451 2029 341,125 2030 236,736 Thereafter 1,877,760 Total $ 3,498,307 Third-Party Debt Our third-party debt consists of (i) non-recourse and limited-recourse project finance debt or acquisition financing debt 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) financing liability related to the business combination purchase transaction of the Terra-Gen geothermal assets; (iv) convertible notes; (v) commercial paper; and (vi) short term revolving credit lines with banks which may be drawn as needed. Non-Recourse, Limited-Recourse, Full-Recourse Third-Party Debt, Financial Liability and Convertible Notes Loan Amount Outstanding as of June 30, 2026 Interest Rate Range Maturity Date (Dollars in millions) Limited and non-recourse loans: fixed rate $ 787.6 2.4% - 7.0% June-30 - July-47 Full recourse loans: Fixed-rate 724.6 2.9% - 7.9% January-28- February-33 Variable-rate 391.1 6.0% - 6.1% September-28 - November-34 Financing liability (1) 213.8 6.0% June-38 2027 Convertible Notes (2) (#) 190.6 2.5% July-27 Series A Convertible Notes (2) 825.0 1.5% March-31 Series B Convertible Notes (2) 175.0 0.0% March 2031 (*) (#) In connection with the 2027 Convertible Notes, the price of the Company's common stock for at least 20 trading days during a period of 30 consecutive trading days ending on the last trading day of the second quarter of 2026, was greater than or equal to 130% of the conversion price on each applicable trading day, allowing holders of the 2027 Convertible Notes to convert all or any portion of their 2027 Convertible Notes at their option prior to the original maturity date. (*) Holders of the Series B Notes may require the Company to repurchase their Series B Notes for cash on March 15, 2027. (1) Financing Liability The financing liability is related to the sale and lease back transaction of the Dixie Valley power plant which was acquired as part of the business combination transaction of the Terra-Gen geothermal assets in July 2021. The financing liability bears a fixed interest rate of 6.0% per annum, principal and interest are payable semi-annually, and it matures in June 2038. (2) Convertible Notes The 2027 Convertible Notes were issued in June 2022 in a single series of a $431.3 million aggregate principal amount. The 2027 Convertible Notes bear annual interest at a rate of 2.5%, payable semiannually in arrears on January 15 and July 15 of each year, beginning on January 15, 2023. The 2027 Convertible Notes mature on July 15, 2027, unless earlier converted, 49 redeemed or repurchased. In July 2024, the Company issued an additional $45.2 million aggregate principal amount of its 2.50% 2027 Convertible Notes. The 2031 Convertible Notes, including the Series A Notes and the Series B Notes, were issued in March 2026. We issued $825 million aggregate principal amount of Series A Notes and $175 million aggregate principal amount of Series B Notes. The Series A Notes bear interest at a rate of 1.50% per year, payable semi-annually in arrears, and the Series B Notes will not bear regular interest. Both series of 2031 Convertible Notes will mature on March 15, 2031, unless earlier converted, redeemed or repurchased. Holders of the Series B Notes will have the right to require the Company to repurchase all or a portion of their 2031 Convertible Notes on March 15, 2027, at a repurchase price equal to 100% of the principal amount, plus any accrued and unpaid special interest, if any. Short-term Commercial Paper In October 2023, the Company completed the issuance of the commercial paper in the aggregate amount of $73.2 million, and subsequently on December 11, 2023, the Company issued an additional amount of $26.8 million, under the same terms of the commercial paper framework agreement (together, the “Commercial Paper”). The Commercial Paper was issued for a period of 90 days and extends automatically for additional 90-day periods for up to five years, unless the Company notifies the participants otherwise or a notice of termination is provided by the participants in accordance with the provisions of the Commercial Paper agreement. The Commercial Paper bears an annual interest of three months SOFR +1.1% which is paid at the end of each 90-day period. As of June 30, 2026, the rate was 4.7%, and the aggregate outstanding amount of the Commercial Paper is $100.0 million. Dividends The Company has declared and distributed quarterly dividends of $0.12 per share during the past two years. Historical Cash Flows The following table sets forth the components of our cash flows for the periods indicated: Six Months Ended June 30, 2026 2025 (Dollars in thousands) Net cash provided by operating activities $ 129,192 $ 184,907 Net cash used in investing activities (262,634) (432,426) Net cash provided by financing activities 511,562 246,930 Translation adjustments on cash and cash equivalents (840) 881 Net change in cash and cash equivalents and restricted cash and cash equivalents $ 377,280 $ 292 For the Six Months Ended June 30, 2026 Net cash provided by operating activities for the six months ended June 30, 2026 was $129.2 million, compared to $184.9 million for the six months ended June 30, 2025, representing a decrease of $55.7 million. Net cash provided by operating activities for the six months ended June 30, 2026 was primarily attributable to net income of $70.6 million, adjusted for certain non-cash items such as depreciation and amortization, write-offs of long-lived assets and unsuccessful exploration activities, income attributable to the sale of tax benefits, bargain purchase gain and deferred income tax provision, among others, and primarily by: (i) a net decrease in accounts payable and accrued expenses of $21.4 million as a result of the timing of payments to our suppliers; (ii) a net change of $24.5 million in the short and long-term costs and estimated earnings in excess of billings on uncompleted contracts and short-term billings in excess of costs and estimated earnings on uncompleted contracts, as a result of the timing of billing to our customers; (iii) a net increase in trade receivables of $12.3 million, due to the timing of collection from our customers; and (iv) a $24.8 million gain from the sale of the TOPP2 power plant. This was partially offset by: (i) $34.4 million expense related to the induced conversion of the 2027 Convertible Notes; (ii) a net decrease of $0.3 million in prepaid expenses and other related to timing of payments; and (iii) a net increase in inventories of $0.6 million, primarily related to the timing of allocating costs to projects under construction. Net cash provided by operating activities for the six months ended June 30, 2025 was primarily attributable to net income of $69.2 million for the period, adjusted for certain non-cash items, such as depreciation and amortization, income attributable to the sale of tax benefits, and deferred income tax provision, among others, and primarily by: (i) a net change of $29.4 million in the short-term costs and estimated earnings in excess of billings on uncompleted contracts and short-term billings in excess of costs and estimated earnings on uncompleted contracts, as a result of the timing of billing to our customers; and (ii) a net decrease in trade receivables of $15.9 million, due to the timing of collection from our customers. This was partially offset by: (i) a net increase of $29.4 million in the long-term costs and estimated earnings in excess of billings on uncompleted contracts related 50 to the Dominica project; (ii) a net decrease in accounts payable and accrued expenses of $18.2 million as a result of the timing of payments to our suppliers; and (iii) a net increase in inventories of $6.8 million, primarily related to the timing of allocating costs to projects under construction. Net cash used in investing activities for the six months ended June 30, 2026 was $262.6 million, compared to $432.4 million for the six months ended June 30, 2025. The principal factors that affected our net cash used in investing activities during the six months ended June 30, 2026, and 2025 were: (i) capital expenditures of $251.8 million during the six months ended June 30, 2026, compared to $327.4 million, in the same period of the prior year, primarily for our facilities under construction that support our growth plan; (ii) cash paid for the business acquisition of the Hoku solar and storage facility of $78.3 million in the six months ended June 30, 2026, compared to $88.7 million cash paid for the Blue Mountain power plant acquisition in the six months ended June 30, 2025; and (iii) $25.6 million cash paid as investment in unconsolidated companies in the six months ended June 30, 2026, compared to $16.3 million for the six months ended June 30, 2025. Additionally, for the six months ended June 30, 2026, cash flow from investing activities included $93.1 million in proceeds from the sale of the TOPP2 power plant as further described under note 1 to the condensed consolidated financial statements. Net cash provided by financing activities for the six months ended June 30, 2026 was $511.6 million, compared to $246.9 million for the six months ended June 30, 2025. The principal factors that affected the net cash provided by financing activities during the six months ended June 30, 2026 were: (i) net proceeds of $976.1 million from issuance of the 2031 Convertible Notes; (ii) proceeds of $50.8 million from tax monetization transactions; (iii) net proceeds of $84.2 million from long-term loans; and (iii) cash received from noncontrolling interest in the amount of $5.5 million. These cash inflows were partially offset by: (i) partial prepayment of the 2027 Convertible Notes of $310.9 million; (ii) net cash paid for revolving credit lines with banks of $80.0 million; (iii) scheduled repayments of long-term debt in the amount of $158.1 million; (iv) purchase of treasury stock of $24.4 million; (v) cash paid in relation to debt issuance and line of credit transactions of $13.3 million; (vi) cash dividend payment of $14.7 million; and (vii) cash paid to noncontrolling interest of $2.6 million . The principal factors that affected our net cash provided by financing activities during the six months ended June 30, 2025 were: (i) net proceeds of $299.3 million from long-term loans entered into during the first half of 2025; (ii) net cash received from revolving credit lines with banks of $96.5 million; and (iii) cash received from noncontrolling interest in the amount of $10.3 million. These cash inflows were partially offset by: (i) scheduled repayments of long-term debt in the amount of $136.8 million; (ii) cash paid in relation to debt issuance transactions of $9.0 million, (iii) cash dividend payment of $14.6 million; and (iv) a cash paid to noncontrolling interest of $3.3 million. Non-GAAP Measures: 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) cost related to a settlement agreement; (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 United States, 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. Net income for the three and six months ended June 30, 2026 was $26.0 million and $70.6 million, respectively, compared to $28.2 million and $69.2 million, for the three and six months ended June 30, 2025, respectively. Adjusted EBITDA for the three and six months ended June 30, 2026 was $143.9 million and $338.8 million, respectively, compared to $134.6 million and $284.9 million, for the three and six months ended June 30, 2025, respectively. The following table reconciles net income to EBITDA and Adjusted EBITDA for the three and six months period ended June 30, 2026 and 2025: 51 Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (Dollars in thousands) Net income $ 26,014 $ 28,199 $ 70,627 $ 69,233 Adjusted for: Interest expense, net (including interest income and amortization of deferred financing costs) 36,867 34,753 80,430 67,913 Income tax provision (benefit) (9,666) (5,466) (25,136) (9,261) Adjustment to investment in unconsolidated companies: our proportionate share in interest expense, tax and depreciation and amortization in Sarulla and Ijen 3,570 3,856 7,060 7,277 Depreciation, amortization and accretion 77,158 70,676 151,501 139,832 EBITDA $ 133,943 $ 132,017 $ 284,483 $ 274,994 Mark-to-market (gains) or losses of derivative instruments (977) (3,343) (791) (2,404) Stock-based compensation 6,244 4,621 10,968 9,533 Allowance for bad debts 1 25 668 51 Induced conversion expense in connection with the issuance of the 2031 Convertible Notes 761 — 34,413 — Impairment of long-lived assets 316 — 8,428 — Merger and acquisition transaction costs 669 1,009 1,432 1,009 Bargain purchase gain — — (9,616) — Settlement agreement expenses and other (3,618) — 168 900 Write-off of unsuccessful exploration and storage activities 6,611 251 8,693 767 Adjusted EBITDA $ 143,950 $ 134,581 $ 338,846 $ 284,850 EBITDA and Adjusted EBITDA include our proportionate share (12.75% and 49%) of Sarulla's and Ijen’s EBITDA and Adjusted EBITDA, respectively. As of June 30, 2026, the outstanding carrying value of long-term debt owed by SOL and Ijen, our unconsolidated investments, was $616.2 million, and $142.5 million, respectively, in which our proportionate share was $78.6 million, and $69.8 million, respectively. Capital Expenditures Our capital expenditures primarily relate to: (i) the development and construction of new power plants, (ii) the enhancement of our existing power plants; and (iii) investment in activities under our strategic plan. The following is an overview of projects that are fully released for construction: Zunil Upgrade (Guatemala). We are expanding the Zunil geothermal power plant in Guatemala to add 5MW of additional capacity. We are planning to sell the electricity generated under the existing PPA with the local utility, Instituto Nacional de Electrificación or “INDE”. Construction has been completed and drilling was delayed. Bouillante Repowering (Guadeloupe). We are currently in the process of upgrading the Bouillante project and planning to install a new Ormat energy converter that will add net capacity of 10MW. Construction is progressing and the PPA was signed. We expect commercial operation in the fourth quarter of 2026. Stillwater Upgrade (U.S.). We are upgrading the power plant that was purchased in January 2024 to add 5MW. The upgrade has been completed with a partial 2MW contribution to the power plant. We expect the rest of the MW to contribute in Q1 2027. Salt Wells Upgrade (U.S.). We are upgrading the power plant that was purchased in January 2024 to add 5MW. Construction is ongoing and we expect commercial operation in the third quarter of 2026. Blue Mountain Upgrade (U.S.). We are upgrading the power plant that was purchased in June 2025 to add 3.5MW. Engineering and procurement is ongoing and commercial operation is expected to start in the first half of 2027. 52 Heber Complex (U.S.) We are currently in the process of upgrading the Heber complex. We are planning to add a new 23MW power plant and increase the output of our current operating power plants by an additional 4MW. Engineering, procurement and manufacturing is ongoing and we expect commercial operation in the second half of 2027. Lone Mountain (U.S.). We are developing a 30MW geothermal power plant in Nevada. Engineering and procurement commenced and we expect commercial operation at the end of 2027 or early 2028. In addition, we are in the process of repowering the Puna power plant and working to add new Solar facilities to support the geothermal auxiliaries in MGH, Blue Mountain, and Heber complex. In the Energy Storage segment, we are currently in the process of constructing several facilities as detailed below: Project Name Size Location Customer Expected COD Bird Dog 60MW/120MWh CA SDCP Q3 2026 Jersey Valley Solar plus Storage 67MW/268MWh NV NV Energy 2027/2028 Griffith 100MW/400MWh CA TBD 2028 Israel High Voltage (*) - Rosh Pina 75MW/300MWh Israel Israeli Electricity Authority 2028 Israel High Voltage (*) - Bet Alpha 75MW/300MWh Israel Israeli Electricity Authority 2028 Bror Hail 20MW/100MWh Israel Israeli Electricity Authority 2028 Denali 100MW/400MWh CA Clean Power Alliance 2028 (*) Represents our share of two projects, which are joint ventures. We have budgeted approximately $1,172.0 million in capital expenditures for the construction of new projects and enhancements to our existing power plants in the Electricity segment, of which we had invested $310.0 million as of June 30, 2026. We expect to invest approximately $178.0 million in the rest of 2026 and the remaining amount of approximately $684.0 million thereafter. In addition, we estimate approximately $271.0 million in additional capital expenditures in 2026 to be allocated as follows: (i) approximately $78.0 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 $25.0 million for maintenance capital expenditures for our operating power plants; (iii) approximately $20 million related to our EGS activities; (iv) approximately $129.0 million for the construction and development of energy storage projects; (iv) approximately $10 million related to business development activities; and (v) approximately $9.0 million for enhancements to our production facilities. In the aggregate, we estimate our total capital expenditures for the rest of 2026 to be approximately $449.0 million. Exposure to Market Risks Based on current conditions, we believe that we have sufficient financial resources to fund our activities and execute our business plans. However, due to various factors (including those discussed in “—General—Trends and Uncertainties” in this quarterly report and in the same section of Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2025 Annual Report), the cost of obtaining financing for our project needs may increase significantly or such financing may be difficult to obtain. 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 the 25 MW PPA for the Puna complex. Our energy storage projects sell primarily on a "merchant" basis and are exposed to changes in the electricity market prices. The prices paid for electricity pursuant to the 25MW PPA for the Puna complex in Hawaii change primarily as a result of variations in the price of oil as well as other commodities. Accordingly, our revenues from this power plant may fluctuate. In 2024, the HPUC approved a new PPA related to Puna with fixed prices, increased capacity and an extension of the term until 2052, which we expect to be in effect in early 2027. As of June 30, 2026, 88.2% of our consolidated long-term debt was at fixed interest rates, and therefore not subject to interest rate volatility risk. During the six months ended June 30, 2026, we issued the 2031 Convertible Notes of which Series 53 A bears a fixed annual interest rate of 1.5% and Series B bears an interest rate of 0.0%. Our short-term commercial paper, which was issued on October 23, 2023, bears an annual interest rate of three months SOFR plus 1.1%, therefore presenting an exposure to interest rate volatility. The outstanding amount of the short-term commercial paper as of June 30, 2026 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 Shekel ("NIS") in Israel, the Euro in Guadeloupe, and the New Zealand Dollar with respect to our operations 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, option 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. We performed a sensitivity analysis on the fair values of our long-term debt obligations, commercial paper and foreign currency exchange forward and option contracts. The foreign currency exchange forward and option contracts listed below principally relate to trading activities. The sensitivity analysis involved increasing and decreasing forward and spot rates at June 30, 2026 and December 31, 2025 by a hypothetical 10% and calculating the resulting change in the fair values. At this time, 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. 54 The results of the sensitivity analysis calculations as of June 30, 2026 and December 31, 2025 are presented below: Assuming a 10% Increase in Rates Assuming a 10% Decrease in Rates Risk June 30, 2026 December 31, 2025 June 30, 2026 December 31, 2025 Change in the Fair Value of: (Dollars in thousands) Foreign currency $ (2,225) $ — $ 2,017 $ — Foreign currency forward and option contracts Interest rate (1,879) — 1,951 — Ormat Geothermal Senior Secured Notes Interest rate (496) (582) 513 605 Mammoth Senior Secured Notes 2025 Interest rate (1,026) (1,397) 1,084 1,477 Dominica Loan Interest rate (2,319) (2,453) 2,429 2,562 GB Loan Interest rate (803) (895) 826 921 Mizrahi 2025 Loan Interest rate (747) (869) 767 893 Discount 2025 Loan Interest rate (805) (930) 827 958 Discount 2025 II Loan Interest rate (2,023) (2,323) 2,089 2,406 Discount 2025 III Loan Interest rate (2,175) (2,547) 2,233 2,620 Hapoalim 2025 Loan Interest rate (2,621) (2,683) 2,778 2,839 Bottleneck Loan Interest rate (4,372) (4,580) 4,682 4,904 Mammoth Senior Secured Notes Interest rate (289) (317) 293 321 Mizrahi Loan Interest rate (538) (592) 552 606 Mizrahi Loan 2023 Interest rate (240) (338) 243 342 Hapoalim Loan Interest rate (1,171) (1,343) 1,201 1,381 Hapoalim Loan 2023 Interest rate (824) (906) 843 927 Hapoalim 2024 Loan Interest rate (106) (147) 107 149 HSBC Loan Interest rate (377) (611) 380 617 HSBC Bank 2024 Loan Interest rate (373) (448) 379 455 Discount Loan Interest rate (392) (438) 402 449 Discount 2024 Loan Interest rate (357) (472) 361 479 Discount 2024 II Loan Interest rate (7,974) (8,347) 8,443 8,853 Financing Liability Interest rate (1,791) (2,042) 1,840 2,101 OFC 2 Senior Secured Notes Interest rate (1,087) (1,259) 1,112 1,288 Olkaria III - DFC Loan Interest rate (685) (723) 705 744 DEG 4 Loan Interest rate (2,761) (2,863) 2,836 2,939 Senior Unsecured Bonds Interest rate (86) (123) 88 125 DEG 2 Loan Interest rate (71) (100) 71 102 DEG 3 Loan Interest rate (829) (962) 858 999 DAC 1 Senior Secured Notes Interest rate (1,454) (1,669) 1,482 1,704 Senior Unsecured Loan (Migdal) Interest rate (698) (749) 737 793 Prudential - NV Interest rate (435) (471) 448 485 DOE Loan Interest rate (1,690) (1,806) 1,795 1,922 Prudential - Idaho Refinancing Loan Interest rate (1,025) (1,160) 1,057 1,198 Platanares DFC Loan Interest rate (133) (17) 133 17 Commercial paper 55 Effect of Inflation Over the last five years, although to a lesser extent since 2024, we experienced an increase in the overall operating and other costs as a result of higher inflation rates, in particular in the U.S. To address the possibility of rising inflation, some of our contracts include certain provisions that mitigate inflation risk. In connection with the Electricity segment, none of our U.S. PPAs, including the SCPPA Portfolio PPA, are directly linked to the Consumer Price Index ("CPI"), although some of them have a fixed annual indexation. Inflation may directly impact the expenses we incur for the operation of our projects, thereby increasing our overall operating costs and reducing our profit and gross margin. The negative impact of inflation would be partially offset by price adjustments built into some of our PPAs that could be triggered upon such occurrences. In addition to the Puna rates that are impacted by higher commodity prices, the energy payments pursuant to our PPAs for some of our power plants such as the Brady power plant, the Steamboat 2 and 3 power plants and the McGinness Complex increase every year through the end of the relevant terms of such agreements, although such increases are not directly linked to the CPI or any other inflationary index. Lease payments are generally fixed, while royalty payments are generally calculated as a percentage of revenues and therefore are not significantly impacted by inflation. In our Product segment, inflation may directly impact fixed and variable costs incurred in the construction of third-party power plants, thereby lowering our profit margins at the Product segment. We are more likely to be able to offset long term, all or part of this inflationary impact through our project pricing. With respect to power plants that we build for our own electricity production, inflationary pricing may impact our operating costs which may be partially offset in the pricing of the new long-term PPAs that we negotiate. Contractual Obligations and Commercial Commitments We have various contractual obligations, which are recorded as liabilities in our consolidated condensed financial statements. Other items are not recognized as liabilities in our consolidated condensed financial statements but are required to be disclosed. There have been no material changes, outside of the ordinary course of business, to our contractual obligations as previously disclosed in our 2025 Annual Report. 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 its PPAs with us, such failure would have a material adverse impact on our financial condition. Also, as we implement 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: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 Sierra Pacific Power Company and Nevada Power Company 13.0 % 12.9 % 11.0 % 14.5 % Southern California Public Power Authority (“SCPPA”) 16.6 17.0 13.5 19.5 Kenya Power and Lighting Co. Ltd. ("KPLC") 12.3 12.5 9.6 12.3 The Company has historically been able to collect on substantially all of its receivable balances. As of June 30, 2026, the amount overdue from KPLC in Kenya was $37.4 million of which $11.7 million was paid in July 2026. The Company believes it will be able to collect all past due amounts from KPLC. 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 June 30, 2026, the total amount overdue from Empresa Nacional de Energía Eléctrica ("ENEE") was $13.1 million of which $3.7 million was paid in July 2026. In addition, due to the financial situation in Honduras, the Company may experience further delays in collection. The Company believes it will be able to collect all past due amounts from ENEE. Government Grants and Tax Benefits A comprehensive discussion on government grants and tax benefits is included in “Part II - Item 7 – Management Discussion and Analysis of Financial Condition and Results of Operation” of our 2025 Annual Report, as updated by “General—Trends and Uncertainties” in Part I, Item 2 of this quarterly report on Form 10-Q. 56