ORMAT TECHNOLOGIES, INC. (ORA) FY 2024 MD&A

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

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

General

Recent Developments

The most significant recent developments for our Company and business during 2024 and 2025 to date are described below:

•In February 2025, we won a tender issued by the Israeli Electricity Authority and have been awarded two separate 15-year tolling agreements for two Energy Storage facilities. The facilities under the tolling agreements are expected to have a combined capacity of approximately 300MW/1200MWh. The ownership of the projects will be shared, 50/50 between Ormat and Allied Infrastructure LTD, a leading infrastructure company in Israel.

•In February 2025, we announced the successful COD for the Ijen geothermal power plant that is owned jointly with PT Medco Power Indonesia (“Medco Power”). The Ijen Geothermal Power Plant, equipped with OEC, began operations with its first phase, delivering 35 MW of electricity power to the Java grid, Ormat’s share of the facility is 17MW. The commencement of this first phase marks a significant step of the Ijen Facility with a total planned capacity of 110 MW under a 30-year PPA.

•In January 2025, we announced the signing of a 10-year PPA with Calpine Energy Solutions, one of North America’s largest energy suppliers. Under this agreement, Calpine Energy Solutions agreed to purchase up to 15MW of clean, renewable energy from the Mammoth 2 geothermal power plant located near Mammoth Lakes, California, to support demand within its retail portfolio. Energy deliveries under the PPA are scheduled to begin in the first quarter of 2027 and will replace the existing PPA with SCE. The new PPA includes an increase in production capacity and a higher price point.

•In December 2024, we announced the successful commencement of commercial operations for our Montague energy storage facility. This 20MW/20MWh Battery Energy Storage System (BESS), located in New Jersey, will provide ancillary services on the merchant market to PJM.

•In December 2024, we announced that we successfully secured 1,678 acres in Utah’s Bureau of Land Management (BLM) Auction. We expect that these lease acquisitions will significantly support our ongoing operations and development projects in the state, further strengthening Ormat’s commitment to advancing renewable energy solutions and meeting Utah’s increasing demand for sustainable energy.

•In December 2024, we announced the pricing of an underwritten secondary offering pursuant to which ORIX Corporation agreed to sell 3,700,000 shares of our common stock. The offering closed on December 13, 2024. Ormat did not offer any new shares of its common stock in the offering and did not receive any proceeds from the sale of the shares being offered by ORIX. The shares of common stock were sold to the public at an initial price of $76.20 per share.

•In November 2024, we signed an EPC contract with Contact Energy for the development of the Te Mihi Stage 2 101MW geothermal power plant in New Zealand. The EPC contract, is valued at approximately $210 million. Te Mihi Stage 2 geothermal power plant is expected to be completed by mid-2027.

•In November 2024, we announced a successful deal to transfer ITCs from the 80MW/320MWh Bottleneck Project to a third-party. The gross proceeds from this transaction were priced at $0.93 per dollar. After deducting the buyer’s broker and legal fees, the net proceeds from the transaction amounted to approximately $46.7 million.

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•In October 2024, we announced the successful commencement of commercial operations for our largest energy storage facility, the Bottleneck project. This 80MW/320MWh BESS, located in the Central Valley of California, will provide ancillary services to San Diego Gas & Electric (“SDG&E”) under a 15-year Tolling Agreement we signed in 2022.

•In October 2024, we announced that we successfully secured multiple land parcels in Nevada’s Annual BLM Auction. We believe that these lease acquisitions will significantly support Ormat's ongoing exploration and expansion efforts in the state, further strengthening the Company's commitment to advancing renewable energy solutions and meeting Nevada's increasing demand for sustainable energy.

•In August 2024, we signed two seven-year tolling agreements with Equilibrium Energy for the Lower Rio 60MW/120MWh and Bird Dog 60MW/120MWh Energy Storage facilities in Texas. The Lower Rio project is expected to come online in the second quarter of 2025, while the Bird Dog facility is anticipated to be operational in the fourth quarter of 2025. Both projects are eligible to receive a 40% investment tax credit under the Inflation Reduction Act, as of the date of this report. The tolling agreements secure fixed revenues for the energy and ancillary services provided by these facilities.

•In July 2024, we issued an additional $45.2 million aggregate principal amount of our 2.50% Convertible Senior Notes due 2027. The additional notes were issued as additional notes pursuant to the indenture, dated June 27, 2022, as supplemented by the first supplemental indenture, dated July 15, 2024. The proceeds were used for refinancing current debt.

•In July 2024, we announced the signing of a 15-year Resource Adequacy Purchase and Sale Agreement (“RA Agreement”) with the City of Riverside, for the 80MW/320MWh Shirk Battery Energy Storage System (BESS) located in Visalia, California. The RA Agreement includes a guaranteed commercial operation date (“COD”) for March 1, 2026, that we believe can be achieved by the end of 2025.

•In the second quarter of 2024, we commenced the operation of the 6MW Beowawe Repower geothermal power plant.

•On March 4, 2024, we announced the signing of a 30-year PPA with Electricité de France (“EDF”) for the development of a new 10MW geothermal power plant on the island of Guadeloupe, in which we own a 63.75% equity interest. The new plant development will be added to Ormat’s existing 15MW Bouillante geothermal power plant. The project’s field development is complete and resources are secured and it is expected to be operational by the end of 2025.

•On February 12, 2024, we announced that the Hawai`i Public Utilities Commission (“HPUC”) approved two final amendments to the PPA between our subsidiary, Puna Geothermal Venture (“PGV”), and Hawaiian Electric. This decision enables PGV to contribute up to an additional 8 megawatts of clean, dispatchable renewable power to the Island of Hawai`i, elevating the contract maximum capacity to 46 MW, with a minimum contracted capacity set at 30 MW. The approval follows PGV’s completion and submission of its final Environmental Impact Study (“EIS”) for operations in Puna, Hawai`i, which was a condition for approval of the amended and restated PPA that we submitted to the HPUC in December 2019.

•On January 4, 2024 we announced the closing of the acquisition of a portfolio of geothermal and solar assets from EGPNA, that was announced in October 2023. Under the agreement, Ormat paid $274.6 million for 100% of the equity interest in the portfolio of assets. The acquired portfolio includes two contracted operating geothermal power plants and one triple hybrid geothermal, solar PV and solar thermal power plant with a total geothermal capacity of approximately 40 MW and solar PV of 20MW, two solar PV assets with a total nameplate capacity of 40 MW, and two greenfield development assets.

Opportunities, Trends and Uncertainties

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

•Increased Demand for Baseload and Data Centers: There has been increased demand for energy generated from geothermal and other renewable resources in the U.S. driven by both baseload requirements and the growing energy needs of data centers.. This is largely due to legislative and regulatory requirements and incentives, such as state RPS and federal tax credits such as PTCs or ITCs (which are discussed in more detail in the section entitled “Government Grants and Tax Benefits” below). We believe that future demand is expected to

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be driven primarily by further commitment to, and implementation of, state RPS and greenhouse gas reduction initiatives.

•Higher Tolling and RA Prices in California: The market in California has seen higher tolling and RA prices. This trend is influenced by the state's aggressive renewable energy targets and the need to ensure grid reliability. The increased prices provide opportunities for higher returns on equity for new projects.

•New Tolling in Texas for Storage Facilities: Texas is introducing new tolling mechanisms for storage facilities. This development is expected to create new opportunities for the development of storage projects, which can enhance grid stability and provide stable revenue streams that mitigate the fluctuation we see from the merchant markets.

•Government Support and Legislative Changes: The U.S. federal government has taken, and we expect it to continue to take, certain actions which are supportive of the broader domestic energy industry, including geothermal heat solutions. The new presidential administration may take action to revise, repeal, or otherwise modify existing rules and regulations, including various tax incentives, and the potential impact on the Company remains uncertain at this time. For more information, see Part I of this Annual Report, Item 1A “Risk Factors—Risks Related to Governmental Regulations, Laws and Taxation —The reduction, elimination or inability to monetize government incentives could adversely affect our business, financial condition, future results and cash flows.”

•Local Support: We expect that a variety of local governmental initiatives will create new opportunities for the development of new projects with the potential to realize higher returns on our equity as well as to create additional markets for our products. These initiatives include the award of long-term contracts to independent power generators, the creation of competitive wholesale markets for selling and trading energy, capacity and related energy products and the adoption of programs designed to encourage “clean” renewable and sustainable energy sources.

•Product Segment Opportunities and Competition: In the Product segment, we believe there are new business opportunities in the U.S., Asia Pacific, New Zealand and Central and South America. We have experienced increased competition from binary power plant equipment suppliers including the major steam turbine manufacturers. While we believe that we have a distinct competitive advantage based on our technology, accumulated experience and current worldwide share of installed binary generation capacity, an increase in competition may impact our ability to secure new purchase orders from potential customers. The increased competition may also lead to further reductions in the prices that we are able to charge for our binary equipment.

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

•Interest Rate Increases: interest rates for both short-term and long-term debt have increased over the last few years, but starting in 2024 we have seen U.S. short term interest rates begin to come down. Although most of our outstanding debt is at fixed interest rates, if we refinance, or borrow additional amounts, we may incur additional interest expense compared to what we currently incur under our existing loans.

Revenues

Sources of Revenues

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

Electricity Segment

Revenues attributable to our Electricity segment are derived from the sale of electricity from our power plants pursuant to long-term PPAs. While approximately 81.3% of our Electricity revenues for the year ended December 31, 2024 were derived from PPAs with fixed price components, we have a variable price PPA in Hawaii, which provide for payments based on the local utilities’ avoided cost. The avoided cost is the incremental cost that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others. In Hawaii, the prices paid for electricity pursuant to the 25 MW PPA for the Puna Complex change primarily as a result of variations in the price of oil as well as other commodities. In 2024, the HPUC approved a new PPA related to Puna with fixed prices, increased capacity and an

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extension of the term until 2052. Accordingly, our revenues from this power plant may fluctuate. Our Electricity segment revenues are also subject to seasonal variations, as more fully described in “Seasonality” below.

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

Product Segment

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

Energy Storage Segment

Revenues attributable to our Energy Storage segment are generated by several grid-connected BESS facilities that we own and operate from selling energy, capacity and/or ancillary services in merchant markets like PJM Interconnect, ISO New England, ERCOT and CAISO or under tolling agreements that have fixed revenues. The revenues fluctuate over time since a large portion of such revenues are generated in the merchant markets, where price volatility is inherent. We are seeking to reduce volatility by increasing the amount of long-term tolling agreements in our portfolio. In 2024 we signed two long-term tolling agreement, that will secure fixed revenues for the 60MW/120MWh Lower Rio and 60MW/120MWh Bird Dog project in Texas.

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

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

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

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Geographic Breakdown of Results of Operations

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

In 2024, 2023 and 2022, 37%, 39% and 34% of our total revenues were derived from foreign locations, respectively, and our foreign operations had higher gross margins than our U.S. operations in each of those years. A substantial portion of the Electricity Segment foreign revenues came from Kenya and, to a lesser extent, from Honduras, Guadeloupe, and Guatemala. Our operations in Kenya contributed disproportionately to gross profit and net income. The contribution to combined pre-tax income of our domestic and foreign operations within our Electricity segment and Product segment differ in a number of ways, as summarized below.

Electricity Segment

Our Electricity segment domestic revenues were approximately 73%, 71% and 71% of our total Electricity segment for the years ended December 31, 2024, 2023 and 2022, respectively. However, domestic operations have higher costs of revenues and expenses than our foreign operations. Our foreign power plants are located in lower-cost regions, like Kenya, Guatemala, Honduras and Guadeloupe, which favorably impact payroll, and maintenance expenses among other items. Our power plants in foreign locations are also newer than most of our domestic power plants and therefore tend to have lower maintenance costs and higher availability factors than our domestic power plants. Consequently, in 2024 and 2023, our foreign operations of the segment accounted for 39% and 44% of our total gross profits, 78% and 63% of our net income (considering the majority of corporate operating and financing expenses are recorded under our domestic operations), and 31% and 36% of our EBITDA, respectively.

Product Segment

Our Product segment foreign revenues were 94%, 94% and 90% of our total Product segment revenues for the years ended December 31, 2024, 2023 and 2022, respectively.

Energy Storage Segment

Our Energy Storage segment domestic revenues were 100.0% of our total Energy storage segment revenues for years ended December 31, 2024, 2023 and 2022, respectively.

Seasonality

Electricity generation from some of our geothermal power plants is subject to seasonal variations. In the winter, our power plants produce more energy primarily attributable to the lower ambient temperature, which has a favorable impact on the energy component of our Electricity segment revenues as the prices under many of our contracts are fixed throughout the year with no time-of-use impact. The prices paid for electricity under the PPAs for the Mammoth Complex

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and the North Brawley power plant in California, the Raft River power plant in Idaho, the Neal Hot Springs power plant in Oregon and Dixie Valley power plant in Nevada, are higher in the months of June through September. The higher payments payable under these PPAs in the summer months partially offset the negative impact on our revenues from lower generation in the summer attributable to a higher ambient temperature. As a result, we expect the revenues and gross profit in the winter months to be higher than the revenues and gross profit in the summer months and in general we expect the first and fourth quarters to generate higher revenues than the second and third quarters. In the Storage segment pursuant to the Bottleneck tolling agreement, approximately 45% of the revenues are generated in the third quarter, and the rest is roughly even between the first, second and fourth quarters.

Breakdown of Cost of Revenues

Electricity Segment

The principal cost of revenues attributable to our operating power plants are operation and maintenance expenses comprised of salaries and related employee benefits, equipment expenses, costs of parts and chemicals, costs related to third-party services, lease expenses, royalties, startup and auxiliary electricity purchases, property taxes, insurance, depreciation and amortization and, for some of our projects, purchases of make-up water for use in our cooling towers. In our California power plants, our principal cost of revenues also includes transmission charges and scheduling charges. In some of our Nevada power plants we also incur transmission and wheeling charges. Some of these expenses, such as parts, third-party services and major maintenance, are not incurred on a regular basis. This results in fluctuations in our expenses and our results of operations for individual power plants from quarter to quarter. Payments made to government agencies and private entities on account of site leases where power plants are located are included in cost of revenues. Royalty payments, included in cost of revenues, are made as compensation for the right to use certain geothermal resources and are paid as a percentage of the revenues derived from the associated geothermal rights. Royalties constituted approximately 4.6% and 4.6% of Electricity segment revenues for the years ended December 31, 2024 and 2023, respectively.

Product Segment

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

Energy Storage Segment

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

Critical Accounting Estimates and Assumptions

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

Revenues and Cost of Revenues

Revenues generated from the construction of geothermal and recovered energy-based power plant equipment and other equipment on behalf of third parties (Product revenues) are recognized using the percentage of completion method, which requires estimates of future costs over the full term of product delivery. Such cost estimates are made by management based on prior operations and specific project characteristics and designs. If management’s estimates of total estimated costs with respect to our Product segment are inaccurate, then the percentage of completion is inaccurate resulting in an

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over- or under-estimate of revenue and gross margin. As a result, we review and update our cost estimates on significant contracts on a quarterly basis, and at least on an annual basis for all others, or when circumstances change and warrant a modification to a previous estimate. Changes in job performance, job conditions, and estimated profitability, including those arising from the application of penalty provisions in relevant contracts and final contract settlements, may result in revisions to costs and revenues and are recognized in the period in which the revisions are determined. Provisions for estimated losses relating to contracts are made in the period in which such losses are determined. Revenues generated from engineering and operating services and sales of products and parts are recorded once the service is provided or product delivered as the customer obtains control of the asset, as applicable.

Property, Plant and Equipment

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

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

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

Our assessment of economic viability of an exploration project involves significant management judgment and uncertainties as to whether a commercially viable resource exists at the time we acquire land rights and begin to capitalize such costs. As a result, it is possible that our initial assessment of a geothermal resource may be incorrect and we will have to write off costs associated with the project that were previously capitalized. Due to the uncertainties inherent in geothermal exploration, historical impairments may not be indicative of future impairments. Included in construction-in-process are costs related to projects in exploration and development of $193.7 million and $162.5 million at December 31, 2024 and 2023, respectively.

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

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

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

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under exploration, development or construction that are not part of an existing complex, at the plant or project level. To the extent an operating plant becomes part of a complex in the future, we will test for impairment at the complex level.

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

If our assets are considered to be impaired, the impairment to be recognized is the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. We believe that for the year ended December 31, 2024, no impairment exists for any of our long-lived assets; however, estimates as to the recoverability of such assets may change based on revised circumstances. Estimates of the fair value of assets require estimating useful lives and selecting a discount rate that reflects the risk inherent in future cash flows.

Goodwill

Goodwill represents the excess of the fair value of consideration transferred in the business combination transactions over the fair value of tangible and intangible assets acquired, net of the fair value of liabilities assumed and the fair value of any noncontrolling interest in the acquisitions. Goodwill is not amortized but rather subject to a periodic impairment testing on an annual basis, which the Company performs on December 31 of each year, or if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount. Additionally, it is permitted to first assess qualitative factors to determine whether a quantitative goodwill impairment test is necessary. Further testing is only required if the entity determines, based on the qualitative assessment, that it is more likely than not that a reporting unit’s fair value is less than its carrying amount. Otherwise, no further impairment testing is required. An entity has the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to the quantitative goodwill impairment test. This would not preclude the entity from performing the qualitative assessment in any subsequent period. The quantitative assessment compares the fair value of the reporting unit to its carrying value, including goodwill. Under ASU 2017-04, Intangibles – Goodwill and Other (Topic 350), an entity should recognize an impairment charge for the amount by which the carrying amount of the reporting unit exceeds its fair value. However, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit.

Obligations Associated with the Retirement of Long-Lived Assets

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

Accounting for Income Taxes

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

We evaluate our ability to utilize the deferred tax assets quarterly and assess the need for a valuation allowance. In assessing the need for a valuation allowance, we estimate future taxable income, including the impacts of the enacted tax law, the feasibility of ongoing tax planning strategies and the realizability of tax credits and tax loss carryforwards.

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Valuation allowances related to deferred tax assets can be affected by changes in tax laws, statutory tax rates, and future taxable income. In the future, if there is insufficient evidence that we will be able to generate sufficient future taxable income in the U.S., we may be required to record a valuation allowance, resulting in income tax loss in our Consolidated Statement of Operations.

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

New Accounting Pronouncements

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

Results of Operations

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

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Results as a percentage of revenues

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Comparison of the year ended December 31, 2023 and the year ended December 31, 2022

A discussion of changes in our results of operations in 2023 compared to 2022 has been omitted from this Form 10-K, but may be found in “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” of our Form 10-K for the fiscal year ended December 31, 2023, filed with the SEC on February 23, 2024, which is incorporated by reference herein. This Form 10-K for the fiscal year ended December 31, 2023 is available free of charge on the SECs website at www.sec.gov and at www.Ormat.com, by clicking “Investors” located at the top of the home page.

Comparison of the Year Ended December 31, 2024 and the Year Ended December 31, 2023

Total Revenues

For the year ended December 31, 2024, our total revenues increased by 6.1% from $829.4 million in 2023 to $879.7 million in 2024.

For the year ended December 31, 2024, our Electricity segment generated 79.8% of our total revenues, compared to 80.4% in the previous year, while our Product segment generated 15.9% of our total revenues, compared to 16.1% in the previous year, and our Energy Storage segment generated 4.3% of our total revenues, compared to 3.5% in the previous year.

Electricity Segment

Revenues attributable to our Electricity segment for the year ended December 31, 2024 were $702.3 million, compared to $666.8 million for the year ended December 31, 2023, representing a 5.3% increase. This increase of $35.5 million was mainly attributable to (i) $33.3 million related to the geothermal and solar power plants included in the Enel purchase transaction which were consolidated by the Company starting the first quarter of 2024; (ii) $17.4 million related to the Puna power plant due to its higher power generation and energy prices in 2024; and (iii) $11.0 million related to the Heber 1 power plant which resumed operations in May 2023 after a temporary shutdown due to a fire incident that occurred in February 2022. This increase was partially offset by a decrease in revenues in 2024 compared to 2023 as follows: (i) $12.8 million in the Dixie Valley power plant due to an unplanned outage in 2024; (ii) $10.3 million in McGinness Hills complex primarily due to curtailments which were mostly related to third-party grid maintenance; (iii) $4.2 million in the Guadeloupe power plant due to lower availability; and (iv) decreases in power generation in lesser amounts at a number of other power plants.

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During the years ended December 31, 2024 and 2023, our consolidated power plants generated 7,450,071 MWh and 7,196,440 MWh, respectively, an increase of 3.5%. The average prices during the years ended December 31, 2024 and 2023 were $94.3, and $92.7 per MWh, respectively.

Product Segment

Revenues attributable to our Product segment for the year ended December 31, 2024 were $139.7 million, compared to $133.8 million for the year ended December 31, 2023, representing a 4.4% increase. The increase is primarily related to the progress in our projects and timing of when revenues are recognized. During 2024, Product revenues included projects primarily in New Zealand and Dominica, compared to 2023, during which Product revenues included projects primarily in New Zealand and Indonesia.

Energy Storage Segment

Revenues attributable to our Energy Storage segment for the year ended December 31, 2024 were $37.7 million compared to $28.9 million for the year ended December 31, 2023, representing a 30.6% increase. This increase of $8.8 million is mainly related to the new energy storage facilities which commenced commercial operation during 2023, such as Bowling Green in May 2023, Andover and Upton in June 2023, and Pomona 2 in July 2023, as well as the East Flemington and Bottleneck energy storage facilities which commenced commercial operations in the first quarter of 2024 and in the fourth quarter 2024, respectively. This increase was partially offset by lower merchant prices in Texas due to mild weather conditions in the area in 2024 compared to 2023, and primarily during the third quarter of 2024 compared to 2023.

Total Cost of Revenues

Electricity Segment

Total cost of revenues attributable to our Electricity segment for the year ended December 31, 2024 was $459.5 million, compared to $422.5 million for the year ended December 31, 2023, representing an 8.8% increase. This increase of $37.0 million is primarily attributable to: (i) $25.5 million related to the geothermal and solar power plants included in the Enel purchase transaction which were consolidated by the Company starting the first quarter of 2024; (ii) $6.3 million of income from business interruption insurance proceeds related to the Puna power plant as a result of the damage caused by the Kilauea volcano eruption in May 2018, which were included as a reduction to cost of revenues in 2023, compared to none in 2024; (iii) $3.4 million primarily related to maintenance issues in the Guadeloupe power plant; and (iv) other increases in lesser amounts at a number of other power plants. This increase was partially offset by lower cost of revenues reduced by $4.3 million at the Heber 1 power plant which resumed operations in May 2023, as described above.

As a percentage of total Electricity revenues, the total cost of revenues attributable to our Electricity segment for the year ended December 31, 2024 was 65.4%, compared to 63.4% for the year ended December 31, 2023. This increase was primarily attributable to higher operational costs and depreciation expenses in some of our power plants as well as the impact of business interruption insurance income included as a reduction to cost of revenues in 2023, as described above. The cost of revenues attributable to our international power plants was 18.3% of our Electricity segment cost of revenues for the year ended December 31, 2024, compared to 18.0% for the year ended December 31, 2023.

Product Segment

Total cost of revenues attributable to our Product segment for the year ended December 31, 2024 was $113.9 million, compared to $115.8 million for the year ended December 31, 2023, representing a 1.6% decrease from the prior year. This decrease was primarily attributable to higher profitability of projects, and therefore lower related costs, in projects for which revenues were recognized in 2024, compared to projects for which revenues were recognized in 2023. As a percentage of total Product segment revenues, our total cost of revenues attributable to our Product segment for the year ended December 31, 2024 was 81.6%, compared to 86.6% for the year ended December 31, 2023.

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Energy Storage Segment

Cost of revenues attributable to our Energy Storage segment for the year ended December 31, 2024 were $33.6 million as compared to $27.1 million in the year ended December 31, 2023. This increase was mainly due to depreciation related to the addition of new energy storage systems to our commercially operating facilities in 2023 and 2024.

Research and Development Expenses

Research and development expenses for the year ended December 31, 2024 were $6.5 million, compared to $7.2 million for the year ended December 31, 2023, represent a 9.9% decrease. This decrease is mainly attributable to the timing of research and development projects that took place during the year ended December 31, 2024 compared to 2023.

Selling and Marketing Expenses

Selling and marketing expenses for the year ended December 31, 2024 were $17.7 million, compared to $18.3 million for the year ended December 31, 2023, representing a 3.3% decrease. Selling and marketing expenses constituted 2.0% and 2.2% of total revenues for the years ended December 31, 2024 and 2023, respectively.

General and Administrative Expenses

General and administrative expenses for the year ended December 31, 2024 were $80.1 million, compared to $68.2 million for the year ended December 31, 2023, representing a 17.5% increase. The increase was primarily attributable to legal fees related to a settlement agreement with a third-party battery systems supplier of $4.0 million, amortization of stock-based awards of $2.3 million, insurance costs of $2.1 million, and timing of when we incur services from our vendors, primarily for legal and information technology services.

General and administrative expenses for the year ended December 31, 2024 constituted 9.1% of total revenues for such period, compared to 8.2%, for the year ended December 31, 2023.

Other Operating Income

Other operating income for the year ended December 31, 2024 was $9.4 million compared to none for the year ended December 31, 2023. Other operating income represents the non-refundable portion of the recovery of damages received from a third-party battery systems supplier as part of a settlement agreement entered into in August 2024 for which all contingency conditions have been met, as further described under Note 1 to the consolidated financial statements.

Impairment of long-lived assets

Impairment of long-lived assets for the year ended December 31, 2024 was $1.3 million compared to none for the year ended December 31, 2023. The impairment of long-lived assets is related to the termination of the waste heat agreement between the Company's wholly-owned subsidiary, OREG4, and Highline Electric Association, Inc., effective May 2024

Write-off of Unsuccessful Exploration and Storage Activities

Write-offs of unsuccessful exploration and storage activities for year ended December 31, 2024 were $3.9 million compared to $3.7 million for the year ended December 31, 2023. These write-offs are primarily related to geothermal exploration projects that the Company decided to no longer pursue, as well as costs related to a number of battery energy storage projects that the Company decided to no longer pursue and develop.

Interest Income

Interest Income for the year ended December 31, 2024 was $7.9 million, compared to $12.0 million for the year ended December 31, 2023. Interest income is primarily related to interest earned on cash and cash equivalents held by the Company during the period. The decrease in interest income is primarily related to lower balances of cash and cash equivalents in 2024 compared to 2023.

Interest Expense, Net

Interest expense, net, for the year ended December 31, 2024 was $134.0 million, compared to $98.9 million for the year ended December 31, 2023, representing a 35.5% increase. This increase of $35.2 million is primarily due to loan agreements entered into during 2023 and 2024, including: (i) the Mizrahi 2023 Loan entered into in November 2023; (ii) the Hapoalim 2023 Loan entered into in February 2023; (iii) the short-term commercial paper entered into in October 2023; (iv) the Hapoalim 2024 Loan entered into in January 2024; (v) the HSBC Bank 2024 Loan entered into in January 2024; (vi) the Mammoth Senior Secured Notes entered into in March 2024; (vii) the DEG 4 Loan entered into in April 2024; (viii) the Discount 2024 Loan entered into in May 2024; (ix) the issuance of the Additional 2.50% Senior Convertible

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Notes in July 2024; (x) the Discount 2024 II Loan entered into in September 2024; and (xi) the Bottleneck Loan entered into in November 2024. 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 losses for the year ended December 31, 2024 was $4.2 million, compared to $3.3 million for the year ended December 31, 2023. Derivatives and foreign currency transaction losses primarily includes losses from foreign currency forward contracts which were not accounted for as hedge transactions, and the impact of changes in foreign currency exchange rates against the U.S. Dollar.

Income Attributable to Sale of Tax Benefits

Income attributable to the sale of tax benefits for the year ended December 31, 2024 was $73.1 million, compared to $61.2 million for the year ended December 31, 2023. This income primarily represents the value of PTCs and taxable income or loss generated by certain of our power plants allocated to investors under tax equity transactions, and to income related to the expected sale of transferable production tax credits under the existing IRA regulations. This increase of $11.9 million is primarily related to the Heber 1 power plant which resumed operations in May 2023, the Beowawe Repower power plant which commenced operations in the second quarter of 2024, and to the increase in the PTCs rates.

Other Non-Operating Income (Expense), Net

Other non-operating income (expense), net for the year ended December 31, 2024 was an income of $0.2 million, compared to an expense of $1.5 million for the year ended December 31, 2023. Other non-operating (expense), net for year ended December 31, 2023 is primarily attributable to $1.2 million related to a settlement and release transaction with a third party entered into in December 2023.

Income Taxes

Income tax (provision) benefit for the year ended December 31, 2024, was a benefit of $16.3 million, a decrease of $22.3 million compared to an income tax provision of $(6.0) million for the year ended December 31, 2023. Our effective tax rate for the year ended December 31, 2024 and 2023, was (14.1)% and 4.3%, respectively. The effective rate differs from the federal statutory rate of 21% for the year ended December 31, 2024 due to the generation of investment tax credits, a net benefit associated with the U.S. state effective tax rate, and the jurisdictional mix of earnings at differing tax rates from the federal statutory tax rate.

Equity in Earnings (losses) of investees, net

Equity in losses of investees, net in the year ended December 31, 2024, was net losses of $0.4 million, compared to net earnings of $35.0 thousand in the year ended December 31, 2023. Equity in earnings (losses) of investees, net is mainly derived from our 12.75% share in the earnings or losses in the Sarulla project, and our 49% share in the earnings or losses in the Ijen geothermal project. The decrease in this line item is primarily related to a decrease in net income generated by the Ijen project in 2024, compared to 2023. In the second quarter of 2022, Sarulla agreed with its banks on a framework that will enable it to perform remediation works that are aimed to restore the power plants' performance. The first phase of the recovery plan included the drilling of an additional production well, which was successful, and certain modifications to surface equipment are still underway. Following the positive indications from the first phase, during the second quarter of 2024, Sarulla commenced discussions with the banks towards implementation of the additional phases.

Net Income attributable to the Company’s Stockholders

Net income attributable to the Company’s stockholders for the year ended December 31, 2024 was $123.7 million, compared to $124.4 million for the year ended December 31, 2023, which represents a decrease of $0.7 million. This decrease was attributable to the decrease in net income which was affected by the factors described above, as well as a decrease in expenses of $1.2 million in net income attributable to noncontrolling interest.

Liquidity and Capital Resources

Overview of Sources and Uses of Cash

Our principal sources of liquidity have been derived from cash flows from operations, proceeds from third-party debt such as borrowings under our credit facilities and issuances of debt securities, equity offerings, project financing and tax monetization transactions, short term borrowing under our lines of credit, and proceeds from the sale of equity interests in

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one or more of our projects. We have utilized this cash to develop and construct power plants, storage facilities, fund our acquisitions, pay down existing outstanding indebtedness, and meet our other cash and liquidity needs.

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

As of December 31, 2024, we had access to: (i) $94.4 million in cash and cash equivalents, of which $73.9 million was held by our foreign subsidiaries; and (ii) $374.1 million of unused corporate borrowing capacity under existing committed lines for credit and letters of credit with different commercial banks.

As of December 31, 2024, $286.6 million in the aggregate was outstanding under credit agreements with several banks as detailed below under “Letters of Credits under the Credit Agreements”.

Our estimated capital needs for 2025 include approximately $570.0 million for capital expenditures on new projects under development or construction including storage projects, exploration activity and maintenance capital expenditures for our existing projects. In addition, we expect $235.7 million for long-term debt repayments.

Our capital expenditures primarily relate to the enhancement of our existing power plants and the construction of new power plants. We have budgeted approximately $460.0 million in capital expenditures for construction of new projects and enhancements to our existing power plants, of which we had invested $135.0 million as of December 31, 2024. We expect to invest approximately $160.0 million in 2025 and the remaining approximately $165.0 million on thereafter.

In addition, we estimate approximately $410.0 million in additional capital expenditures in 2025 to be allocated as follows: (i) approximately $140.0 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 $55.0 million for maintenance of capital expenditures to our Electricity segment operating power plants; (iii) approximately $200.0 million for the construction and development of storage projects; and (iv) approximately $15.0 million for enhancements to our production facilities.

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

Letters of Credits under the Credit Agreements

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

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

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, a prohibition on: (i) creating any floating charge or any permanent pledge, charge or lien over our assets without obtaining the prior written approval of the lender; (ii)

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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 December 31, 2024: (i) total equity was $2,550.9 million and the actual equity to total assets ratio was 45.0%; and (ii) the 12-month debt, net of cash and cash equivalents to Adjusted EBITDA ratio was 4.03. During the year ended December 31, 2024, we distributed interim dividends in an aggregate amount of $29.1 million. The failure to perform or observe any of the covenants set forth in such agreements, subject to various cure periods, would result in the occurrence of an event of default and would enable the lenders to accelerate all amounts due under each such agreement.

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

As of December 31, 2024, we did not meet the dividend distribution criteria related to the financing liability (which was assumed by the Company as part of the purchase transaction with TG Geothermal Portfolio, LLC in July 2021), which resulted in certain equity distribution restrictions from this related subsidiary. The amount restricted for distribution by this subsidiary was $1.4 million as of December 31, 2024. There were no restrictions on the retained earnings or net income of Ormat Technologies, Inc., as the parent company, in respect of this matter, as of December 31, 2024.

Credit Agreements

Credit Agreement with MUFG Union Bank

Ormat Nevada has a credit agreement with MUFG Union Bank under which it has an aggregate available credit of up to $100.0 million as of December 31, 2024. The credit termination date is June 30, 2025.

The facility is limited to the issuance, extension, modification or amendment of letters of credit. Union Bank is currently the sole lender and issuing bank under the credit agreement, but is also designated as an administrative agent on behalf of banks that may, from time to time in the future, join the credit agreement as lenders. In connection with this transaction, the Company entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which the Company agreed to guarantee Ormat Nevada’s obligations under the credit agreement. Ormat Nevada’s obligations under the credit agreement are otherwise unsecured. There are various restrictive covenants under the credit agreement, which include a requirement to comply with the following financial ratios, which are measured quarterly: (i) a 12-month debt to EBITDA ratio not to exceed 4.5; (ii) 12-month DSCR of not less than 1.35; and (iii) distribution leverage ratio not to exceed 2.0. As of December 31, 2024: (i) the actual 12-month debt to EBITDA ratio was 1.90; (ii) the 12-month DSCR was 5.32; and (iii) the distribution leverage ratio was 0.4. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios, and subject to specified carve-outs and exceptions, a negative pledge on the assets of Ormat Nevada in favor of Union Bank. As of December 31, 2024, the covenants have been met.

As of December 31, 2024, letters of credit in the aggregate amount of $86.7 million were issued and outstanding under this credit agreement.

Credit Agreement with HSBC Bank USA N.A.

Ormat Nevada has a credit agreement with HSBC Bank USA, N.A for one year with annual renewals. The current expiration date of the facility under this credit agreement is October 31, 2025. On December 31, 2024, the aggregate amount available under the credit agreement was $35.0 million. This credit line is limited to the issuance, extension, modification or amendment of letters of credit. In addition, Ormat Nevada has an uncommitted discretionary demand line of credit in the aggregate amount of $65.0 million available for letters of credit including up to $20 million of credit. In connection with this transaction, the Company entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which the Company agreed to guarantee Ormat Nevada’s obligations under the credit agreement. Ormat Nevada’s obligations under the credit agreement are otherwise unsecured.

There are various restrictive covenants under the credit agreement, including a requirement to comply with the following financial ratios, which are measured quarterly: (i) a 12-month debt to EBITDA ratio not to exceed 4.5; (ii) 12-month DSCR of not less than 1.35; and (iii) distribution leverage ratio not to exceed 2.0. As of December 31, 2024: (i) the

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actual 12-month debt to EBITDA ratio was 1.90; (ii) the 12-month DSCR was 5.32; and (iii) the distribution leverage ratio was 0.4. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios, and subject to specified carve-outs and exceptions, a negative pledge on the assets of Ormat Nevada in favor of HSBC. As of December 31, 2024, the covenants have been met.

As of December 31, 2024, letters of credit in the aggregate amount of $34.8 million were issued and outstanding under the committed portion of this credit agreement and $36.9 million under the uncommitted portion of the agreement.

Future minimum payments

Future minimum payments under long-term obligations as of December 31, 2024, are detailed under the caption Contractual Obligations and Commercial Commitments, below.

Third-Party Debt

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

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

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

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

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

(1) Secured by equity interest.

(2) Secured by the assets.

(3) Loan in Euros and issued amount is EUR 8.0 million

Full-Recourse Third-Party Debt:

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(1) Interest rate includes the effect of the IR Swap as further described under Note 11 to the consolidated financial statements.

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

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

Other Third-Party Debt

For additional description of our long-term debt, see Note 11, Long-term Debt, Credit Agreements and Financial Liability to our consolidated financial statements, set forth in Item 8 of this Annual Report.

On February 2, 2025, we entered into a definitive loan agreement with Mizrahi Bank under which the bank provided a loan in an aggregate principal amount of $50 million. The outstanding principal amount of the this loan will be repaid in 16 semi-annual payments of $3.1 million each, commencing on October 15, 2025. The duration of the loan is 8 years and it bears interest of 6-month SOFR+2.35%, payable every six months. For additional description of our long-term debt entered into subsequent to December 31, 2024, see Note 22 - Subsequent events, to our consolidated financial statements, set forth in Item 8 of this Annual Report.

Liquidity Impact of Uncertain Tax Positions

As discussed in Note 16 - Income Taxes, to our consolidated financial statements set forth in Item 8 of this Annual Report, we have a liability associated with unrecognized tax benefits and related interest and penalties in the amount of approximately $6.3 million as of December 31, 2024. This liability is included in long-term liabilities in our consolidated balance sheet, because we generally do not anticipate that settlement of the liability will require payment of cash within the

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next 12 months. We are not able to reasonably estimate when we will make any cash payments required to settle this liability.

Dividends

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

The following are the dividends declared by us during the past two years, as of December 31, 2024:

Historical Cash Flows

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

For the Year Ended December 31, 2024

Net cash provided by operating activities for the year ended December 31, 2024 was $410.9 million, compared to $309.4 million for the year ended December 31, 2023, representing a net increase of $101.5 million. Net cash provided by operating activities for the year ended December 31, 2024, was primarily attributable to net income of $131.2 million adjusted for certain non-cash items such as depreciation and amortization, stock-based compensation, and income attributable to sale of tax benefits, among others, as well as primarily by: (i) cash inflow related to the net decrease in trade receivables of $27.2 million, due to the timing of collection from our customers; (ii) a net increase in accounts payable and accrued expenses of $11.4 million as a result of timing of payments to our suppliers, and a payment related to recovery of damages received from a third-party battery systems supplier as part of a settlement agreement; (iii) a net increase in prepaid expenses and other of $8.5 million, primarily as a result of timing of prepayments to our suppliers and governmental authorities; and (iv) a net decrease of $6.9 million in inventory, primarily related to the progress of our Product projects and timing of allocating costs to such projects. This increase was partially offset a net increase of $32.3 million in costs and estimated earnings in excess of billings on uncompleted contracts and billings in excess of costs and estimated earnings on uncompleted contracts, as a result of timing of billing to our customers, and a net increase in deposit and others of $4.5 million related to timing of payment deposits required for ongoing operations. Net cash provided by operating activities for the year ended December 31, 2023, was primarily attributable net income of $133.1 million adjusted

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for certain non-cash items such as depreciation and amortization, stock-based compensation, and income attributable to sale of tax benefits, among others, as well as by primarily: (i) a net increase in accounts payable and accrued expenses of $68.6 million, primarily as a result of timing of payments to our suppliers; (ii) a net decrease of $7.9 million in costs and estimated earnings in excess of billings on uncompleted contracts and billings in excess of costs and estimated earnings on uncompleted contracts, as a result of timing of billing to our customers; and (iii) an increase of $10.7 million in other liabilities, net, primarily as a result of of a prepayment made by one of our customers. This increase was partially offset by: (i) a net increase of $97.6 million in trade receivables due to timing of collection from our customers; (ii) a net increase in inventory of $22.2 million, primarily related to the progress of our product projects and timing of allocating costs to such projects; and (iii) a net increase of $7.9 million in prepaid expenses and other primarily as a result of timing of prepayments to our supplier and governmental authorities

Net cash used in investing activities for the year ended December 31, 2024 was $780.3 million, compared to $628.3 million for the year ended December 31, 2023. The principal factors that affected the increase in our net cash used in investing activities during the year ended December 31, 2024 were: (i) capital expenditures of $487.7 million in 2024 compared to $618.4 million in 2023, primarily for our geothermal power plants and storage facilities under construction that support our growth plan; (ii) cash consideration paid in the purchase transaction with EGPNA of $274.6 million in 2024, compared to none in 2023; and (iii) cash outflow for investments in unconsolidated companies of $19.0 million in 2024, compared to $10.2 million in 2023.

Net cash provided by financing activities for the year ended December 31, 2024 was $287.9 million, compared to $380.0 million for the year ended December 31, 2023. The principal factors that affected the decrease in net cash provided by financing activities during the year ended December 31, 2024 were: (i) net proceeds of $514.6 million from long-term loans entered into during the period such as the Hapoalim 2024 Loan, the HSBC 2024 Loan, the Mammoth Senior Secured Notes, the DEG 4 Loan, the Discount 2024 Loan, the Discount 2024 II Loan, and the Bottleneck Loan; (ii) net proceeds of $44.0 million related to proceeds from issuance of the Additional Notes; and (iii) cash received from noncontrolling interest in the amount of $12.3 million. These cash inflows were partially offset by: (i) scheduled repayments of long-term debt in the amount of $209.3 million; (ii) cash dividend payments of $29.1 million; (iii) cash paid persuant to a transaction with noncontrolling interest of $9.8 million; and (iv) net repayments of revolving credit lines with banks of $20.0 million. The principal factors that affected our net cash provided by financing activities during the year ended December 31, 2023 were: (i) net proceeds from issuance of common stock of $341.7 million; (ii) net proceeds from issuance of long-term loans of $149.8 million; (iii) net proceeds of $100.0 million from issuance of commercial paper; and (iii) net proceeds from revolving credit lines with banks of $20.0 million. These cash inflows were partially offset by: (i) scheduled repayments of long-term debt in the amount of $207.0 million; (ii) cash outflow related to a transaction with noncontrolling interest of $30.0 million; and (iii) cash dividend payments of $28.4 million.

For the Year Ended December 31, 2023

A discussion of changes in our cash flows in 2023 compared to 2022 has been omitted from this Form10-K, but may be found in “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” of our Form 10-K for the fiscal year ended December 31, 2023, filed with the SEC on February 23, 2024, which is incorporated by reference herein. This Form 10-K is available free of charge on the SECs website at www.sec.gov and at www.Ormat.com, by clicking “Investors” located at the top of the home page.

Total EBITDA and Adjusted EBITDA

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

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

Net income for the year ended December 31, 2024 was $131.2 million, compared to $133.1 million for the year ended December 31, 2023 and $77.8 million for the year ended December 31, 2022.

Adjusted EBITDA for the year ended December 31, 2024 was $550.5 million, compared to $481.7 million for the year ended December 31, 2023 and $435.5 million for the year ended December 31, 2022.

The following table reconciles net income to EBITDA and Adjusted EBITDA for the years ended December 31, 2024, 2023 and 2022:

Adjusted EBITDA for fiscal year 2024 increased by 14.3% compared to fiscal year 2023, primarily due to an increase in operating income of $5.9 million, or 4%, together with an increase in income attributable to sale of tax benefits of $11.9 million, or 19%. EBITDA and Adjusted EBITDA include our proportionate share (12.75%) of Sarulla's EBITDA and Adjusted EBITDA, respectively. On May 2014, the Sarulla consortium (“SOL”) closed $1,170 million in financing. As of December 31, 2024, the credit facility has an outstanding balance of $717.6 million. Our proportionate share in the SOL credit facility is $91.5 million. See Note 5, investment in unconsolidated companies to the consolidated financial statements for further information relating to our investment in the Sarulla consortium.

Exposure to Market Risks

We, like other power plant operators, are exposed to electricity price volatility risk. Our exposure to such market risk is currently limited because the majority of our long-term PPAs have fixed or escalating rate provisions that limit our exposure to changes in electricity prices, except for 25 MW PPA for the Puna complex. Our energy storage projects sell primarily on a "merchant" basis and are exposed to changes in the electricity market prices. The Puna Complex is currently

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benefiting from energy prices which are higher than the floor under the 25 MW PPA for the Puna Complex as a result of higher fuel costs that impact HELCO's avoided cost. In 2024, the HPUC approved a new PPA for our Puna power plant, which has a fixed energy price with no escalation and de-links it from oil prices, as discussed above.

As of December 31, 2024, 97.9% of our consolidated long-term debt was at fixed interest rates and therefore was not subject to interest rate volatility risk. Additionally, our short-term commercial paper, which was issued on October 23, 2023, bears an annual interest of three months SOFR +1.1%, and therefore presents an exposure to interest rate volatility. The outstanding amount of the short-term commercial paper as of December 31, 2024 was $100.0 million.

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

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

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

We performed a sensitivity analysis on the fair values of our long-term debt obligations, commercial paper, and foreign currency exchange forward contracts. The foreign currency exchange forward contracts listed below principally relate to trading activities. The sensitivity analysis involved increasing and decreasing forward rates at December 31, 2024 and 2023 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.

The results of the sensitivity analysis calculations as of December 31, 2024 and 2023 are presented below:

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Effect of Inflation

Over the last four years, although to a lesser extent during 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. In addition, we are experiencing an increase in raw material costs and supply chain delays, which may put an additional pressure on our operating margins in the Product segment and continues to increase our cost to build our own power plants and energy storage assets. 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"). Inflation may directly impact an expense 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.

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Interest rate increases for both short-term and long-term debt have increased sharply. Although our outstanding debt bears fixed interest rates, as we refinance it, or borrow additional amounts, we may incur additional interest expense versus expiring loans.

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

Contractual Obligations and Commercial Commitments

The following tables set forth our material contractual obligations as of December 31, 2024 :

(1)See interest rates and maturity dates under Liquidity and Capital Resources section above.

(2)The above amounts were determined based on employees’ current salary rates and the number of years’ service that will have been accumulated at their expected retirement date.

(3)We purchase raw materials for inventories, construction-in-process and services from a variety of vendors. During the normal course of business, in order to manage manufacturing lead times and help assure adequate supply, we enter into agreements with contract manufacturers and suppliers that either allow them to procure goods and services based upon specifications defined by us, or that establish parameters defining our requirements. At December 31, 2024, total obligations related to such supplier agreements were approximately $408.2 million (approximately $233.2 million of which relate to construction-in-process). All such obligations are payable in 2025.

(4)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 will be paid at the end of each 90-day period. As of December 31, 2024, the base rate was 4.6%.

The table above does not reflect unrecognized tax benefits of $6.3 million, the timing of which is uncertain. Refer to Note 16 to our consolidated financial statements set forth in Item 8 of this Annual Report for additional discussion of unrecognized tax benefits. The above table also does not reflect a liability associated with the sale of tax benefits of $152.3 million, and other long-term liabilities of $29.3 million, primarily related to a prepayment from one of our customers. Refer to Note 12 to our consolidated financial statements as set forth in Item 8 of this Annual Report for additional discussion of our liability associated with the sale of tax benefits.

Concentration of Credit Risk

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

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

We have historically been able to collect on substantially all of our receivable balances. As of December 31, 2024, the amount overdue from KPLC in Kenya was $38.3 million of which $20.0 million was paid in January and February of 2025. The Company believes it will be able to collect all past due amounts in Kenya. This belief is supported by the fact that in addition to KPLC's obligations under its power purchase agreement, the Company holds a support letter from the Government of Kenya that covers certain cases of KPLC non-payment (such as non-payments that are caused by government actions and/or political events).

In Honduras, as of December 31, 2024, the total amount overdue from ENEE was $16.2 million of which $2.5 million was collected in January and February of 2025. In addition, due to the financial situation in Honduras, the Company may experience additional delays in collection. The Company believes it will be able to collect all past due amounts in Honduras.

Government Grants and Tax Benefits

On August 16, 2022, the then President of the U.S. signed into law the Inflation Reduction Act of 2022 (the “IRA"), which is effective for taxable years beginning after December 31, 2022. The IRA included several tax incentives to promote climate change mitigation and clean energy, electric vehicles, battery and energy storage manufacture or purchase. Some of these measures may materially affect our consolidated financial statements, and we are in the process of evaluating the IRA and identifying potential effects of the IRA as more guidance is issued. Furthermore, the IRA introduces the following: (i) a new corporate alternative minimum tax of 15% on adjusted financial statement income of corporations with profits greater than $1 billion over a three-year period; and (ii) an excise tax of 1% of the fair market value of any stock which is repurchased, reduced by any stock issued during the taxable year. The IRA also includes significant tax incentives for energy and climate initiatives related to Production Tax Credits (“PTC”) and Investment Tax Credits (“ITC”), including extending ITCs to energy storage projects for assets placed in service after December 31, 2022 and the ability to transfer or sell PTCs to other taxpayers.

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

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

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