ORMAT TECHNOLOGIES, INC.

Previous wording

•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.

Current wording

•In February 2025, we announced the successful COD for the Ijen geothermal power plant that is owned jointly with PT Medco Power Indonesia (“Medco Power”). The Ijen Geothermal Power Plant, equipped with Ormat Energy Converter, began operations with its first phase, delivering 35MW of electricity power to the Java grid, Ormat’s share of the facility is 17MW.

Previous wording

•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.

Current wording

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

Previous wording

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 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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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:

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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 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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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”.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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

Previous wording

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.

Current wording

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