on the Company A. History and Development of the Company We were incorporated in March 2014 under the Singapore Companies Act to be the holding company of certain companies that were owned (in whole, or in part) by IC in connection with our Spin-Off from IC in January 2015. Since the Spin-Off, we have sold or distributed our interests in: • ZIM, a large provider of global container shipping services; • the Latin American and Caribbean power generation and distribution business of IC Power; • Tower Semiconductor Ltd., a semiconductor manufacturing company (“Tower”); and • a portion of our interests in Qoros, a China-based automotive company, reducing our ownership from 50% to 12%. We currently own an approximately 46% interest in OPC, an owner, developer and operator of power generation facilities in the Israeli and U.S. power market. We also own a 12% interest in Qoros, a China-based automotive company; we agreed to sell our remaining 12% stake in Qoros in 2022, which has not closed and is the subject of arbitration and litigation awards in our favor. 39 The legal and commercial name of Kenon is Kenon Holdings Ltd. Our principal place of business is located at 1 Temasek Avenue #37-02B, Millenia Tower, Singapore 039192. Our telephone number at our principal place of business is +65 6351 1780. Our internet address is www.kenon-holdings.com. We have appointed Gornitzky & Co., Advocates and Notaries, as our agent for service of process in connection with certain claims which may be made in Israel. Our ordinary shares are listed on the NYSE and the TASE under the symbol “KEN.” The SEC also maintains a website that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. B. Business Overview We are a holding company initially established to promote the growth and development of our primary businesses. Since our Spin-Off over ten years ago, our businesses and our holdings have substantially evolved and unlocked substantial shareholder value, with Kenon demonstrating a track record of achieving strong shareholder returns. Our primary business today, OPC, is listed on the TASE in Israel. We initially listed OPC on the TASE in August 2017 with an initial pre-money market capitalization of $350 million, which has grown to approximately $11 billion as of March 30, 2026. The value of our initial interest, together with our investments totaling approximately $408 million since the IPO, has grown to approximately $5 billion as of March 30, 2026. In November 2025, we sold 5,422,648 OPC ordinary shares for gross proceeds of NIS 340 million (approximately $100 million). We currently own approximately 46% of OPC. Shortly after the IPO, we sold the Inkia Business, our energy business in Latin America and the Caribbean, for approximately $1.3 billion (approximately $1.1 billion net of taxes, fees and costs) and have an award in our favor in respect of a bilateral investment treaty claim against Peru (of which our share was approximately $90 million, subject to tax, as of March 30, 2026); there is no assurance we will be successful in recovering these amounts in full or at all. See “—Inkia Business—Claim Relating to the Inkia Business—Bilateral Investment Treaty Claim Relating to Peru” below. Our initial 32% stake in ZIM at the time of the Spin-Off had been acquired for $200 million, and through the time of our sale of our remaining interests in ZIM in 2024 we had realized approximately $2.1 billion from our interests in ZIM, including the proceeds from the sale of all of our ZIM shares, the proceeds from the termination of a collar transaction utilizing our ZIM shares (and the related sale of those shares) and total dividends received from ZIM. We no longer hold any shares in ZIM. We had entered into a cash settled capped call transaction with respect to five million shares of ZIM, and we have settled this transaction with the bank that provided the collar for cash proceeds of $34 million received in the first quarter of 2026. In addition, we had a 50% stake in Qoros at the time of the Spin-Off and had guaranteed significant amounts of Qoros’ debt. Subsequently, we engaged in transactions reducing our stake in Qoros to 12% and we have received cash payments and release of guarantees of over $450 million (including approximately $75 million in respect of amounts subsequently repaid to Ansonia in respect of various loans provided directly to Quantum to fund its investment in Qoros). In addition, we currently have judgments in our favor in relation to our remaining interest in Qoros (of which our claim in respect of the sale of our remaining interest totals approximately RMB 1.9 billion (approximately $272 million)); there is no assurance we will be successful in recovering these amounts in full or at all. See “—Qoros” below. We have made significant distributions to shareholders, totaling $2.6 billion in cash and listed securities, since our Spin-Off. In 2015, we distributed substantially all of our interest in Tower, with a then-market value of $245 million. In addition, since 2018, we have distributed to shareholders total cash of approximately $2.4 billion from various sources including from portions of the proceeds of our sale of the Inkia Business, a portion of our interest in Qoros (including amounts repaid by Qoros in respect of shareholder loans) and the sale of our stake in ZIM, as well as from dividends received from ZIM. In addition, since March 2023, we have engaged in repurchases of shares under our Repurchase Plan and to date we have repurchased 1.8 million shares for approximately $48 million. In March 2026, we announced a further dividend of approximately $200 million. 40 In addition to these distributions, our market capitalization has grown substantially since the Spin-Off. On March 30, 2026, Kenon’s market capitalization was $4 billion, as compared to our initial market capitalization at the time of our listing of $1.0 billion (based on the closing price of our shares on the TASE on January 11, 2015). Kenon has a strong financial position. In addition to our shareholding of approximately 46% of OPC, as of March 30, 2026 we had cash and cash equivalents and other investments of approximately $708 million and no material debt. We seek to generate attractive returns on our cash and cash equivalents, and seek to use treasury management solutions with credit ratings that are rated investment grade. We are continuing to consider various ways to further maximize value for our shareholders, including potential new investments in new businesses. We believe that in the current market environment, there could be attractive investment opportunities to generate positive shareholder returns. As a company with a strong financial position, no material debt and a history of successfully owning businesses, we believe we are well-positioned to take advantage of such opportunities, which may include investments or acquisitions in new businesses, including majority or wholly-owned positions, joint ventures or minority-owned positions. We expect that such acquisitions or other investments, if any, would be in established industries, would be substantial and that we would be actively involved in the operations and promoting the growth and development of such businesses. In addition, we do not expect that any such acquisitions or other investments would be in start-up companies or focused on emerging markets. We may also try to maximize value for our shareholders through investments in our existing businesses. Since the Spin-Off, we have made significant investments in our existing businesses, including investments during 2025 of approximately $89 million in OPC (approximately $408 million in total since its IPO) to support its growth. OPC, together with its U.S. subsidiary CPV, has projects in construction and under development, with a strategy contemplating continued development of projects and potential acquisitions in Israel, the U.S. and elsewhere. OPC’s growth strategy could present us with opportunities to make further significant equity investments at the OPC level and we may make further investments in OPC. We now hold approximately 46% of OPC’s ordinary shares. We may fund such acquisitions or investments in new or existing businesses through cash on hand, sales of interests in our businesses or by raising new financing. OPC's strategy includes, in the United States, increasing its holdings in existing energy transition power plants and continuing to develop projects, including the Maryland (745 MW), Shore (725 MW), Basin Ranch (1.35 GW) and Shay (2.1 GW) projects; and in Israel, continuing to develop projects such as the Hadera 2 (850 MW), Ramat Bekka (550 MW + 3,850 MWh PV + storage) and Intel (600 MW) projects. These investments and projects require significant financing and OPC has raised significant equity financing to finance these projects. Kenon has supported OPC in pursuing this strategy by participating in a number of these equity raises, and Kenon may make further investments in OPC to support its growth and consolidation strategies. In addition, Kenon will continue to consider the return of capital to shareholders through dividends and/or share repurchases, based on market conditions, capital requirements, potential investment opportunities and other relevant considerations. In March 2026, Kenon announced a dividend of approximately $200 million. Including the dividend announced in March 2026, Kenon has returned more than $2.8 billion in cash and listed securities to shareholders since its Spin-Off in 2015. Our Businesses Set forth below is a description of our primary business OPC. OPC’s Business Information in this annual report relating to OPC (including CPV Group) is based on OPC’s annual report, financial statements and board of directors report for the year ended December 31, 2025, which were published by OPC on March 12, 2026. English translations of OPC’s financial statements and board of directors’ report for 2025 were furnished by Kenon on Form 6-K, dated March 12, 2026. OPC, which accounted for all of our revenues in the year ended December 31, 2025, is a global independent power producer (IPP) engaged in the generation and supply of power and energy. OPC’s generation facilities are located in Israel and, through CPV, the United States. OPC has the following three operating segments: 41 • Israel (through OPC Israel): through this segment, OPC is engaged in the generation and supply of electricity and energy to private customers and to Noga (the System Operator in Israel) and the development, construction and operation of power plants and energy generation facilities powered using natural gas and renewable energy co-located with energy storage in Israel; • U.S. Energy Transition (through CPV Group): through this segment, OPC (through CPV Group) is engaged mainly in the operation of conventional energy power plants (gas-fired) which supply electricity, mostly to the grid. As of December 31, 2025, all power plants in this segment were held by CPV Group through associates, with various holdings (which are not consolidated in CPV Group’s or OPC’s financial statements). CPV Group acquired the remaining stake of approximately 11% of the Shore power plant which was completed in the first quarter of 2026, following which Shore became wholly-owned (100%) by CPV Group. Furthermore, an agreement was signed to acquire the remaining ownership interests in the Maryland power plant, which OPC expects to complete in the second quarter of 2026. This demonstrates OPC’s ongoing strategic initiative to increase CPV Group’s holdings in certain active power plants, and CPV acquired additional stakes in some projects in 2025 as described below; and • U.S. Renewable Energies (through CPV Group): through this segment, OPC (through CPV Group) is engaged in the initiation, development, construction and operation of generation facilities using renewable energy in the United States (mainly solar and wind) and supply of electricity from renewable sources to customers. Furthermore, OPC (through CPV Group) is engaged in additional business activities in the United States. These additional activities include: (i) development and construction of high-efficiency conventional energy (natural gas) projects with future carbon capture potential, and (ii) retail operations for the sale of electricity which is designed to supplement CPV Group’s generation facilities Operations Overview The following tables set forth a summary structure chart of OPC as well as summary operational information regarding OPC’s power plants in commercial operation and under construction and in development in Israel (held and operated by OPC Israel which is 80% owned by OPC) and the United States (held and operated by CPV Group which is approximately 71% owned by OPC). 42 OPC’s Operations in Israel OPC’s Operations in the United States OPC’s Operations in the United States (cont.) 43 Israel Plants in Commercial Operation The following table sets forth key details regarding power plants under OPC’s commercial operation: Power plant/ energy generation facilities Capacity(1) (MW) OPC Israel Ownership Interest Location Type of project / technology Year of commercial operation Rotem 466 100% Mishor Rotem Natural gas, combined cycle 2013 Hadera(2) 144 100% Hadera Natural gas, cogeneration 2020 Zomet 396 100% Plugot Intersection Natural gas, open-cycle 2023 Gat 75 100% Kiryat Gat industrial park Natural gas, combined cycle 2019 (acquired in 2023) Energy generation facilities on the consumers’ premises 45 (of which 10 are in various trial run and operational stages)(3) 100% On consumers’ premises across Israel Natural gas and renewable energy (solar) 2024-2025 ___________________________ (1) As stipulated in the relevant generation license. (2) Hadera owns the Hadera Energy Center (boilers and turbines located at the premises of Infinya), which serves as back-up for steam generated by the Hadera power plant. (3) The commercial operation stage of the consumer-sited facilities may vary from one facility to another, in accordance with each facility’s characteristics. OPC has facilities with a capacity of approximately 10 MW, which are either under construction or undergoing post construction delivery inspections (most are gas-fired facilities and some are solar), with commercial operation expected in 2026. In addition, OPC has additional storage projects under development, totaling approximately 290 MW/h. OPC Israel holds a virtual supply license to sell power to customers. Israel—Projects under Construction and Advanced Development The following table sets forth summary information regarding OPC’s projects under construction in Israel. Power plants / energy generation facilities Status Capacity (MW) Location Technology Expected commercial operation date Main customer/ consumer Sorek 2 Construction has been substantively completed; under pre-commissioning delivery inspections Approximately 87 On the premises of the Sorek B seawater desalination facility Natural gas-fired cogeneration 2026(1) Onsite consumers and the System Operator Natural gas projects with Migdal Early stage Various Option Land Conventional (1) A delay in the commercial operation by Sorek 2 beyond the original contractual date, which is not deemed a “justified” delay as defined in the project agreements, may trigger the payment of a limited-rate graduated monthly compensation (taking into consideration the duration of the delay, with a delay beyond the utilization of the compensation cap possibly giving rise to a termination right). According to the construction contractor and equipment supplier, the security developments in Israel constitute a force majeure and accordingly the construction contractor demanded that an increase in costs be recognized. Sorek 2 informed IDE and the Israeli government that scheduled overruns and delays in the completion of construction by the contractor are expected due to a force majeure, and has submitted a request for recognition of expenses due to force majeure events. 44 Key details regarding projects under Development in Israel Power plant/ energy generation and related facilities Expected Capacity (MW) Status Location Technology Ramat Bekka Approximately 550MW with an estimated storage capacity of up to approximately 3,850 MWh(1) Advanced Development Neot Hovav Local Industrial Council PV co-located with storage Hadera 2 Approximately 850 MW Advanced development Land adjacent to the Hadera power plant Natural gas, combined cycle Solar and storage projects with integrated storage Agreements totaling approximately 0.5 GW (plus an estimated storage capacity of approximately 2.5 GWh) Initial development Kibbutzim/Moshavim PV co-located with energy storage, including agrivoltaic Intel Approximately 450-650 MW (according to OPC's estimate- approximately 600 megawatts) Initial development Gat Natural gas, combined cycle ______________________________________________ (1) OPC is conducting technical feasibility assessments alongside an economic optimization analysis regarding the option of increasing the solar capacity to up to 600 MW plus estimated storage capacity of up to 4,200 MW/h. United States The following table sets forth summary information regarding OPC’s United States operations (plants in commercial operation), through its approximately 71% ownership of CPV Group. Data is presented based on CPV Group’s ownership interests in the projects (renewable energy projects: 66.7%; natural gas projects with carbon capture potential: 70% or 100%, pursuant to the rights in each project): Electricity generation and supply using conventional technologies and renewables The table below sets forth an overview of CPV’s power plants that were in commercial operation as of March 12, 2026. Project Location Installed Capacity (MW) CPV ownership interest Year of commercial operation Type of project/ technology / client Regulated market Energy Transition Projects – Natural Gas Fired CPV Fairview, LLC (“Fairview”) Pennsylvania 1,050 25% 2019 Gas-fired, combined cycle PJM MAAC CPV Towantic, LLC (“Towantic”) Connecticut 805 26% 2018 Gas-fired (with dual fuel), combined cycle ISO-NE CT CPV Maryland, LLC (“Maryland”) Maryland 745 75%(1) 2017 Gas-fired, combined cycle PJM SW MAAC CPV Shore Holdings, LLC (“Shore”) New Jersey 725 100%(1)(2)(as of Jan 2026) 2016 Gas-fired, combined cycle PJM EMAAC CPV Valley Holdings, LLC (“Valley”) New York 720 50% 2018 Gas-fired, combined cycle NYISO Zone G CPV Three Rivers, LLC (“Three Rivers”) Illinois 1,258 10%(3) 2023 Natural gas, combined cycle PJM COMED Renewable Energy Projects (held by CPV Renewables)(4) CPV Keenan II Renewable Energy Company, LLC (“Keenan”) Oklahoma 152 66.7%(5) 2010 Wind SPP (Long-term PPA) CPV Mountain Wind Holdings, LLC (“Mountain Wind”)(6) Maine 82 66.7% Between 2008 and 2017 Wind (4 wind power plants) ISO-NE market CPV Maple Hill Solar LLC (“Maple Hill”) Pennsylvania 126 MWdc 66.7%(7) (subject to tax equity partner’s share) Second half of 2023 Solar PJM MAAC + PA SRECs CPV Stagecoach Solar, LLC (“Stagecoach”) Georgia 102 MWdc 66.7%(8) (subject to tax equity partner’s share) First half of 2024 Solar SERC, the project entered into a long-term PPA (including SRECs) CPV Backbone Solar, LLC (“Backbone”) Maryland 179 MWdc(9) 66.7% (subject to the tax equity partner’s share)(10) Q4 2025 Solar PJM + MD SRECs (1) As of December 31, 2025, CPV Group held approximately 75% in Maryland. In March 2026, CPV Group entered into an agreement (the “Maryland-Three Rivers Exchange Agreement”) with the other partner in Maryland (the “Partner”) for the exchange of the remaining 25% ownership interest in Maryland, for CPV Group’s 10% interest in Three Rivers (the “Maryland-Three Rivers Exchange Transaction”). Following completion (which is expected by OPC to be in the second quarter of 2026), CPV Group’s stake in Maryland would increase to 100%, resulting in consolidation of Maryland in CPV Group’s and consequently in OPC’s financial statements. OPC continues to examine the tax implications of the transaction and its possible impact on its financial results. 45 (2) CPV Group’s interest in Shore increased to approximately 89% in April 2025, following the closing of a purchase agreement entered into in February 2025 with one of the partners in the project, following which Shore remained an associate company. On October 28, 2025, CPV Group (through a wholly owned subsidiary), entered into a purchase agreement with the remaining partner in Shore for the acquisition of the seller’s approximately 11% ownership interest in Shore. The acquisition closed in January 2026. (3) As of December 31, 2025, CPV Group held a 10% ownership interest in Three Rivers. In March 2026, CPV Group entered into the Maryland-Three Rivers Exchange Agreement with the Partner (as discussed above). Following completion (which is expected by OPC to be in the second quarter of 2026), CPV Group would no longer hold any interest in Three Rivers. (4) On August 16, 2024, subsidiaries of CPV Group entered into agreements with Harrison Street, a U.S. private equity fund in the field of infrastructure (the “Investor”), pursuant to which the Investor invested a total $300 million in CPV Renewables for 33.33% of the equity interests in CPV Renewables, which holds 100% in CPV Group’s renewable projects under construction and in development. (5) Represents CPV Group’s holding in the project after giving effect to the Investor’s investment in CPV Renewables. (6) Represents CPV Group’s holding in the project after giving effect to the Investor’s investment in CPV Renewables. (7) Represents CPV Group’s holding in the project after giving effect to the Investor’s investment in CPV Renewables. In May 2023, a “tax equity partner” completed a $82 million investment. The agreement with the tax equity partner gave the tax equity partner the option to sell its equity to CPV Group for a specified amount. (8) Represents CPV Group’s holding in the project after giving effect to the Investor’s investment in CPV Renewables. In May 2024, CPV Group entered into an agreement with a “tax equity partner” for an investment in the project of approximately $52 million. The tax equity partner funded an investment of approximately $43 million, with approximately $9 million to be funded over the term of the agreement as a function of the project’s production pursuant to the agreement. The agreement gives CPV Group the option to acquire the tax equity partner’s share in the project within a certain period of time. (9) The Backbone project has an expansion of additional 36 MWdc (“Backbone Expansion”) (in addition to the current operating capacity of 179 MWdc) which is currently in construction and its commercial operation is expected in the second half of 2026. The expected commercial operation date may be delayed due to construction delays or in case one or more risk factors materializes. Delays beyond the expected commercial operation date may adversely affect the project, including with respect to tax benefits. (10) Represents CPV Group’s holding in the project after giving effect to the Investor’s investment in CPV Renewables. 46 Projects under Construction The table below sets forth an overview of CPV Group’s projects under construction as of December 31, 2025. Project Location Planned Capacity (MW) CPV Ownership Interest Projected date of commercial operation Type of project/ technology Regulated market after PPA period Expected commercial structure Renewable Energy Projects CPV Rogue’s Wind, LLC (“Rogue’s Wind”)(2) Pennsylvania 114 MWdc 66.7% (subject to the tax equity partner’s share) 2026 Wind Turbines PJM MAAC Sale of Electricity on the PJM Market. In April 2021, CPV Group signed an agreement for the sale of all the electricity and the benefits of the Rogue’s Wind energy project (including Renewable Energy Certificates (RECs), benefits related to availability, and related expenses). The agreement was signed for a period of 10 years commencing on the commercial operation date. PJM Capacity Auctions. Natural gas power plant project (with future potential for carbon capture) CPV Basin Ranch Holdings, LLC (“Basin Ranch”) Texas 1,350 MW 100%(1) (as of February 2026) 2029 Natural gas; project with carbon capture potential ERCOT – West Sale of electricity in the ERCOT market (energy only). The project entered into agreements to hedge a material portion of the power plant’s capacity for a period of 7 years from the commercial operation date as part of a plan to hedge approximately 75% of the capacity on the commercial operation date. Such agreements are gas netback agreements (including a pricing mechanism in which the price of gas paid by the electricity producer is derived from the price of electricity) and PPAs. (1) In the third quarter of 2024, the Basin Ranch natural gas power plant project in Texas was chosen by TEF (Texas Energy Fund) to advance to the due diligence stage for receipt of a subsidized loan (“TEF Loan”) on the condition that the construction thereof begins by the end of 2025. In October 2025, the TEF Loan was executed, financial closing of the Basin Ranch project was completed (the “Financial Closing”), including funding of equity, and construction stage commenced. On October 28, 2025, the financial closing of the Basin Ranch project was completed, pursuant to which, among other things, the following agreements and actions became effective (after conditions precedent were fulfilled): (i) funding of the full equity commitment as required by the TEF Loan (in cash, letters of credit, credit or other form acceptable under the TEF Loan); (ii) execution of the EPC Agreement with the Basin Ranch project’s construction contractor; (iii) closing of the Bank Leumi Loan Agreement in connection with a portion of the required equity; and (iv) execution and closing of the full TEF Loan agreements including the first drawdown of the TEF Loan. Additional collateral related to the Basin Ranch project was provided by the equity holders of the project as of such date as part of the financial closing of the TEF Loan. At the Financial Closing date, a Notice to Proceed was issued to the construction contractor for the commencement of the construction phase and additional agreements of the Basin Ranch project became effective, including in respect of its commercialization, additional components of its construction and its operations. OPC’s estimated expected cost of construction of the Basin Ranch project is between approximately $1.8 billion to $2 billion. (2) On October 28, 2025, CPV Group (through wholly owned subsidiaries), entered into a purchase agreement with the remaining partner in the Basin Ranch project (the “Seller”) for the acquisition of the Seller’s remaining 30% ownership interest in the Basin Ranch project which was closed on February 2, 2026, following fulfillment of the conditions. (3) In 2025, the tax equity partner agreement was executed. 47 Projects under Development In addition to the projects summarized above, CPV Group has a pipeline of renewable energy projects (solar and wind energy technologies) at various stages of development, and conventional gas-fired projects with future carbon potential (subject to development of this component). The renewable energy pipeline has an aggregate capacity of approximately 4,220 MWdc, of which CPV Group's share is approximately 2,815 MWdc. CPV Group also has a backlog of Low Carbon Projects with an aggregate capacity of approximately 5,025 MW, of which CPV Group's share is approximately 4,395 MW. In each case, these projects are at various stages of development. The main development activities for a development project include, among other things, the following processes (as applicable depending on, among other things, the technology, location and market): securing of the land rights in the project; licensing and permitting processes; obtaining permits and regulatory approvals, regulatory zoning processes and public hearing; environmental surveys; engineering studies and tests (including studies designated for carbon capture component of Low Carbon Projects); equipment testing, insurance procurement and ensuring of interconnection to the relevant transmission grids (including filing a request for the interconnection agreement, qualifying for the relevant interconnection process/stages and execution of an interconnection agreement) and other infrastructure; signing agreements with relevant tax equity partners or lenders with relevant investors or lenders and relevant suppliers (construction contractors, equipment and turbine contractors) and entering into hedge agreements, commercialization frameworks and/or PPAs, and RECs (as applicable based on the type of project). Certain development activities may include the provision of collateral and undertakings to third parties in connection with the advancement of the projects. The table below sets forth a summary of the scope of CPV’s renewable energy development projects (in MW). Renewable energy Advanced Development Initial development Total PJM Market Solar 70 1,540 1,610 Wind – 130 130 Total PJM Market (1) 70 1,670 1,740 Other markets Solar 240 1,050 1,290 Wind – 1,200 1,200 Total other markets 240 2,250 2,490 Total renewable energy (2) 310 3,920 4,230 Share of CPV Group (66.7%) 205 2,610 2,815 (1) The grid interconnection request process in the PJM market (the “Interconnection Queue”), which constitutes a significant milestone in a project's development, can be lengthy and may take on average two to three years. CPV believes that delays in this process have occurred and may continue to cause delays in the timetables for development of certain projects, taking into account, among other things, the required costs for upgrading the network, the project’s position in the connection process, and the costs of the connection process where upgrades are necessary. (2) All the advanced-stage development projects and certain early-stage development projects, with an aggregate capacity of about 1.9 GW (of which CPV Group's share is approximately 1.3 GW), are expected to comply with applicable safe harbor rules (threshold conditions that must be met in order to qualify for certain tax benefits, including ITC and PTC). CPV Group has invested, and expects to make additional investments, aggregating an estimated tens of millions of dollars in such projects, primarily for the procurement of equipment. OPC’s Strategy Set forth below is OPC’s strategy for as published in OPC’s 2025 annual report. 48 OPC’s vision is to continue strengthening its position as a leading global independent power producer (IPP) operating in two key markets, Israel and the United States, which are characterized by a substantial growth in demand for electricity and tailwind from the business and regulatory environment. Within this framework, OPC: • works to expand its activities and global standing, by, among other things, further developing energy projects in the United States (including by increasing its holdings in certain operational gas-fired projects), while periodically assessing opportunities to expand its activities in the field of electricity generation and supply in additional geographic regions beyond Israel and the United States (such as Europe) and which are consistent with OPC’s strategy and area of activity in terms of technology types, scope, etc.; • operates under a hybrid model which aims to effectively and optimally combine natural gas, renewable energy and energy storage in order to ensure reliable electricity supply, while supporting a clean energy future. OPC seeks to promote energy transition, through a variety of energy production and supply solutions. These solutions include advanced conventional means of natural gas-fired production characterized by high efficiency, continuity and reliability, as well as renewable energy sources (solar, wind and storage); • is based on the values of high professional standards, transparency, fairness, reliability, operational and organizational excellence, technological innovation, and environmental commitment, and is carried out in partnership with all its stakeholders and out of commitment to their evolving needs, specifically customers, employees, communities, investors and credit providers; and • is active across the entire value chain of its activity, from the initiation, construction and development phases of projects, through the operational and production phases to the supply phase, while seeking to optimally utilize the synergies generated between its areas of activity. OPC’s vision is based on an assumption that the independent electricity market in general, and in Israel and in the United States in particular, is expected to continue to expand. This assumption is supported by public forecasts of various entities, according to which the increasing demand for electricity is expected to continue due to, among other things, the increase in demand for server farms, artificial intelligence (AI) applications, electrified transportation and policy of transition to low-carbon economy, that encourages electrification. This assumption is influenced by various factors that are beyond OPC's control. To realize this vision, OPC continues to focus on achieving competitive advantages in (i) initiating constructing and developing facilities using a range of technologies—including conventional technologies and renewable sources; (ii) continuing to establish global activity that combines stability resulting from flows arising from contractual agreements in a growing market and a balanced profit profile throughout the business cycle; (iii) promoting initiatives and transactions to maximize OPC’s positioning in line with demand trends in its areas of activity; (iv) operating and maintaining its power plants; and (v) optimizing and creating synergy in the management of energy sales to customers, through a range of generation sources and ancillary operational and commercial arrangements, and optimizing natural gas procurement, while entering into a range of contracts to enable continuity of supply at a competitive price. OPC’s objectives include (i) acting to expand generation capacity in Israel and the United States by the further development and construction of new projects, and assessing relevant acquisition or investment opportunities (subject to adequate market conditions and at the discretion of OPC’s competent corporate authorities); expanding its activity both in Israel and in the United States using innovative and effective conventional means (natural gas) combined with renewable energies, while establishing its position and experience in project execution; this approach reflects the understanding that combining of these technologies is essential to the promotion of cleaner and low-emission energy (energy transition) alongside a non-interruptible, reliable and efficient electricity supply; (ii) acting to identify and realize business opportunities for the acquisition of further stakes in operational natural gas-fired projects in the United States in order to increase stakes and fully realize the business synergies inherent in this area of activity, subject to reaching agreement with other parties and adequate market conditions (if any); and (iii) to further diversifying OPC’s customer mix (including retail in the United States) and to diversify the mix between revenues from long-term agreements (at fixed prices or with relatively low volatility) versus revenues exposed to market volatility. 49 OPC’s board has adopted an organization-wide ESG policy that is incorporated synergistically into the business strategy and targets discussed above, with the aim of promoting OPC’s commitment to environmental, social and corporate governance principles, in accordance with the international standards in this field, and in a manner that reflects OPC’s continued commitment to all stakeholders, specifically customers, employees, investors, partners and the communities in which OPC operates. With the support of a global consultancy firm specializing in this field, OPC has begun implementing a multi-year work plan based on the aforementioned policy, focusing on material topics it has identified and on achieving the established targets. In addition, OPC’s board has appointed an ESG Committee which supports and monitors the process of implementing the ESG values and compliance with targets set across all areas of activity and which reports to OPC’s board on its activity. From time to time, OPC may explore possibilities for expanding its activities in the electricity and energy generation and supply segment in additional territories around the world, including by (i) constructing and/or acquiring active power plants (using renewable energy and storage), (ii) acquiring power plants under construction or under development, and (iii) developing projects that are deemed suitable and consistent with OPC's business plans. OPC’s strategy for CPV Group’s focuses on promoting energy transition in the United States through the following: • Expanding and increasing position in Energy Transition and Low Carbon Projects for dispatchable reliable electricity generation, for example, by (i) pursuing opportunities to increase CPV Group’s holdings in certain operational power plants, subject to the negotiation of terms with the other holders in such power plants; (ii) continuing to develop Low Carbon Projects to support projected increased demand while maintaining grid reliability with specific focus on the Shay project and its development milestones including interconnection and commercialization with the intention to reach construction within the next approximately two years. • Developing and operating renewable energy projects by (i) developing and constructing new renewable projects, especially projects that qualify under the “safe harbor” rules; and (ii) continuing to develop activity in markets where renewable demand is high and there is a supportive regulatory environment. • Vertical integration by growing retail electric sales to commercial and industrial customers, with supply sourced from CPV Group’s projects or the market, and developing and implementing ESG goals, consistent with CPV Group’s strategy to align financial goals and company values. OPC’s Description of Operations Israel OPC’s operations in Israel include power generation plants that operate on natural gas and diesel. As of December 31, 2025, OPC’s installed capacity of its active plants was approximately 1,081 MW. OPC’s activity in Israel is conducted through OPC’s subsidiary, OPC Israel, in which OPC has an 80% interest and Veridis owns the remaining 20% interest. OPC Israel owns and operates all of OPC’s business activities in the energy and electricity generation and supply sectors in Israel, including a 100% interest in four power plants in operation: Rotem, Hadera, Zomet and Gat. OPC Israel also has projects under construction and in development in Israel, including a 100% interest in Sorek 2 (currently under construction), as well other operations in Israel including energy generation facilities on consumers’ premises and virtual electricity supply activities. Generation of Electricity Set forth below is summary information relating to OPC’s plants in operation. Rotem OPC’s first power plant, Rotem, is powered by conventional technology (natural gas in combined cycle; with diesel oil and crude oil as backups) and has an installed capacity of 466 MW under its conventional technology electricity generation license, valid for a 30-year period from March 2011. Rotem commenced commercial operations in Mishor Rotem, Israel in July 2013 and in 2024 it received a supply license with a license period that corresponds to the period of the generation license, which allows Rotem to trade capacity and energy with other suppliers. 50 Rotem operates according to a tender issued by the state of Israel in 2001 and, in accordance therewith, Rotem signed a PPA with the IEC in November 2009 (“Rotem’s PPA with the IEC”), which sets forth OPC’s regulatory framework. As part of the IEC Reform, this PPA was reassigned by the IEC to Noga, the System Operator such that part of the PPA continues to apply to the IEC. The term of Rotem’s PPA with the IEC is 20 years from the power station’s COD (which was in 2013). According to the agreement, Rotem is entitled to operate in one of the following two ways (or a combination of both, subject to certain restrictions set in the agreement): (i) provide the entire net available capacity of its power station to the Noga or (ii) carve out energy and capacity for direct sales to private consumers. Rotem has allocated the entire capacity of the plant to private consumers since COD. In addition, Rotem has entered into PPAs with large retailers (“Resellers”) for the sale of electricity to Resellers’ customers which are household consumers and small- and medium-size businesses (“SMBs”). Under Rotem’s PPA with the IEC, it can also elect to revert back to supplying to the IEC instead of private customers, subject to twelve months’ advance notice. The introduction of renewable energies into the region in which Rotem is located and grid restrictions may cause the power plant to generate less electricity. In November 2017, Rotem applied to the EA to obtain a supply license for the sale of electricity to customers in Israel. In February 2018, the EA responded that Rotem needs a supply license to continue selling electricity to customers and that the license will not change the terms of the PPA between Rotem and the IEC. Hadera Hadera operates a cogeneration power station in Israel, with capacity of approximately 144 MW. The cogeneration power plant reached its COD on July 1, 2020. Hadera holds a license for generation of electricity using cogeneration technology, which has been granted by the EA for a period of 20 years which may be extended by an additional 10 years. Hadera also holds the supply license which is effective for as long as Hadera holds a valid generation license. Hadera owns the Hadera Energy Center, which consists of boilers and a steam turbine. The Hadera Energy Center currently serves as back-up for the Hadera power plant’s supply of steam and its turbine is not currently operating (and is not expected to operate with generation of more than 16MW). The Hadera power plant is “dual-fuels” generator of electricity (capable of using both natural gas and diesel oil, in its operations, subject to required adjustments). Hadera’s power plant supplies the electricity and steam needs of the facility of Infinya, and provides electricity to private customers in Israel. It also sells electricity to the IEC. The power plant operates using natural gas as its energy source, and diesel oil and crude oil as backups. In order to benefit from the fixed arrangements for cogeneration electricity producers, each generation unit in a power plant must meet the minimum energy utilization conditions set forth in the Cogeneration Regulations, and if it does not meet them, other less favorable tariff arrangements will apply. Hadera is entitled to sell at a tariff, the formula for the calculation of which is predetermined and includes USD mechanisms for linkage to various parameters, including Hadera’s global gas price (including taxes), the CPI and the exchange rate. Following the revision of the demand hours clusters resolution, the mid-peak demand hour cluster was canceled, and the off-peak hours were expanded so as to reduce the System Operator’s purchase obligation from Hadera. The annual tariff is set according to the actual quantity of electricity provided during on-peak hours. 51 In addition to the Hadera power plant, Hadera owns the Hadera Energy Center (boilers and turbine on the premises of the Infinya plants), which is located on the premises of Hadera Infinya plants. In addition, the Hadera Power Plant supplies electricity to additional private customers and to the System Operator. Zomet Zomet owns a natural gas-fired open-cycle power station in Israel with capacity of approximately 396 MW. The Zomet power plant is a “peaking” facility and all capacity is sold to the IEC. OPC Israel owns 100% of the shares of Zomet. The Zomet plant reached COD in June 2023 and the EA has granted an electricity generation license to Zomet for a period of 20 years. As opposed to generation facilities with an integrated cycle that operates during most of the hours in the year, the Zomet power plant is an open-cycle power plant (peaker plant). Peaker plants are generally planned to operate for a short number of hours during the day, where there is a gap in the demand and supply of electricity, e.g., at peak demand times. They act as backup plants whose purpose is to provide availability in times of peak demand, such as when other generation facilities break down, or as supplements when solar energy is unavailable. Therefore, as opposed to Rotem and Hadera, which enter into PPAs to sell power to private customers, Zomet sells all of its energy and capacity from its facilities to Noga (acting as a peaker plant) in accordance with the Zomet PPA (as described below) based on an approved Zomet tariff. 52 Gat Power Plant The Gat Power Plant operates a combined cycle power station powered by conventional energy, with installed capacity of approximately 75 MW. The Gat Power Plant began operations in November 2019, upon being awarded generation and supply licenses by the EA. The Gat Power Plant is located in the Kiryat Gat area. The Gat Power Plant was acquired by OPC in March 2023. The Gat Power Plant operates under a “limited capacity” regulatory framework, in accordance with the applicable regulation for cogeneration producers which do not meet the cogeneration conditions of the EA’s resolution. Under the regulation, Gat is allowed to sell electricity to electricity consumers, and to provide the remaining generation capacity to the System Operator as capacity, under an annual capacity limit. The Gat Power Plant has a tariff approval from the EA in connection with the receipt of capacity payments, where the total capacity payment is capped as per the license. The Gat Power Plant’s revenues from sale of energy are linked to the generation component; therefore, its profitability is affected by changes in the generation component (revenues from provision of capacity are linked to the CPI). 53 The Gat Power Plant is subject to the cogeneration regulations pursuant to which, among other things, the EA set an arrangement (“a hedged availability transaction”) for electricity producers which no longer meet the conditions required for a cogeneration facility. The EA has approved a tariff arrangement which defines the capacity tariffs, to which the Gat Power Plant is entitled from the System Operator. The capacity payment is capped. Distributed Energy (Agreements for construction of energy-generation facilities on consumers’ premises) OPC entered into a number of agreements with consumers (including under a tender of the EA), pursuant to which OPC constructs and operates energy generation facilities on the consumer’s premises using mainly gas-fired electricity generation facilities and electricity storage facilities. As part of the arrangements, OPC is typically given the right to construct generation facilities, setting commercial operation dates subject to conditions, which may differ between agreements; these conditions include meeting various milestones in the project’s life (such as, among others, obtaining permits, connecting to the natural gas distribution grid or to the electrical grid). Currently, facilities have been operated with an aggregate capacity of about 45 MW (of which approximately 10 MW are in various test run and operation stage) and additional facilities with an aggregate capacity of approximately 10 MW are in various stages of construction with an expectation of commercial operation in 2026. The total construction costs in respect of approximately 55 MW are estimated at about NIS 175 million (approximately $55 million). Following the War, OPC served force majeure notices to consumers. The War and its effects have caused schedule overruns for commercial operation and affected the projects’ expected costs. Delays in the completion of the projects, which are not justified in accordance with the relevant agreements, may impact the cost of the project, and may cause an increase in costs and/or constitute failure to comply with undertakings to third parties and lead to the claims or proceedings. Additional facilities in respect of which OPC entered into development agreements in addition to the capacity mentioned above, will not be executed and the agreement in respect thereof was terminated or is in the process of being terminated. OPC is conducting a process in which it is currently examining the possibility of selling this activity. 54 Sorek 2 In May 2020, Sorek 2 (a special-purpose company wholly-owned by OPC) signed an agreement with SMS IDE Ltd. (“IDE”), which won a tender from the State of Israel for the construction, operation, maintenance and transfer of a seawater desalination facility on the Sorek B site (the “Desalination Facility”), whereby Sorek 2 is to supply equipment, construct, operate, and maintain a natural gas-powered energy generation facility on the Sorek B site, with a production capacity of 87 MW (the “Sorek Generation Facility”). The Sorek Generation Facility will supply the energy required for the Desalination Facility for a period that will end upon the earlier of (i) 24 years and 11 months from the Desalination Facility’s commercial operation date, and (ii) March 15, 2048. At the end of this period, ownership of the Sorek 2 Generation Facility will be transferred to the State of Israel. Sorek 2’s engagement with IDE includes, among other things, undertakings by Sorek 2 to construct the facility by the later of: (i) 24 months of the date of approval of National Infrastructures Plan 36A (which became effective in December 2021) or (ii) four months from the date on which the construction of the gas pipeline is completed, including obtaining the required permits, and the supply of gas to the power plant has commenced. The Sorek Generation Facility was built by Sorek 2 as an IPP contractor (subcontractor of the concessionaire) under the BOT (or build, operate, transfer) agreement of the Desalination Facility. The Sorek Generation Facility is expected to be established under the framework of the EA’s resolution on the “Regulatory Scheme for High Voltage Producers Connected to the Grid that are Established without a Tender”, and the capacity remaining beyond the consumption of the Desalination Facility is designated to be sold to the onsite consumer and the System Operator. In December 2024, Sorek 2 signed a PPA with Noga, which regulates Sorek 2’s right to sell Noga capacity and energy, and the terms and conditions for such sale. The PPA became effective on its signing date for a period of 20 years of the date that commercial operation of the generation facility commences. OPC provided IDE with a guarantee of Sorek 2’s commitments under the Sorek B IPP Agreement. In connection with the project, Sorek 2 also entered into the equipment supply agreement (which was subsequently assigned to the construction contractor) for the supply of the gas turbine and related equipment (the “Equipment Supply Agreement”), and a maintenance agreement with General Electric (“GE”) group. OPC estimates that the construction cost of the Sorek 2 project, including its share in the construction agreement and the equipment supply agreement, which constitute most of the cost for the project (excluding the long-term maintenance agreement), is approximately $42 million. On June 4, 2024, the EA issued a tariff approval for Sorek 2 in accordance with the EA’s resolution dated March 6, 2019, on the “Regulatory Scheme for High Voltage Producers Connected to the Grid that are Established without a Tender”. The project reached financial closing on June 6, 2024. Sorek 2 will be eligible to the fixed tariffs as part of the tariff approval, in respect of sale of capacity and energy to Noga, for a period of twenty years commencing on the date of receipt of the permanent generation license and the commercial operation date, subject to conditions, including meeting the deadlines for commercial operation of the Sorek generation facility. In December 2024, Sorek 2 signed a PPA with the System Operator, which regulates Sorek 2’s right to sell the System Operator capacity and energy, and the terms and conditions for such sales. The PPA will have a duration of 20 years from the date of commencement of commercial operation of the generation facility, which has not yet occurred. Currently, certain actions and conditions associated with the construction and operation of the project have not been completed. During the fourth quarter of 2023, the construction contractor of the Sorek 2 project delivered a force majeure notification due to outbreak of the War. The construction work, its completion the commercial operation date and the costs involved with the construction have been adversely impacted by the War, according to which delays were due to, among other things, difficulties in the arrival of foreign work teams to the site, professionals’ departures, and the arrival of equipment to the site. Following an escalation of the War and Operation Rising Lion, in 2024 and 2025, notices were received from BHI CO Ltd (“BHI”) and GE regarding evacuation of the contractors’ foreign workers from Israel due to security situation. A delay in the commercial operation by Sorek 2 beyond the original contractual date, which is not deemed a justified delay as defined in the project agreements, may trigger the payment of a limited-rate graduated monthly compensation (taking into consideration the duration of the delay, with a delay beyond the utilization of the compensation cap possibly giving rise to a termination right). The construction works, their completion, the commercial operation date, and the construction costs were affected by, among other things the security developments in Israel. The construction of the Sorek 2 Generation Facility, which is undergoing delivery inspections, has been substantially completed, and the operation of the generation facility is subject to the fulfillment of conditions and factors which have not yet been fulfilled and to operational or technical factors pertaining to the facility’s delivery inspections. 55 According to the construction contractor and the equipment supplier, the security situation prevalent in Israel constitutes a force majeure, and accordingly the construction contractor demanded that an increase in costs be recognized. Sorek 2 has informed IDE and the Israeli government that schedule overruns and delays in the completion of construction by the contractor are expected due to the matters discussed above, and has submitted a request, in accordance with the project agreements, to recognize higher expenses due to the continued effects of force majeure events on the project. There is no certainty regarding the outcome of Sorek 2’s request. Such schedule overruns may result in an increase in the project costs and could constitute failure to comply with undertakings to such third parties. The ultimate consequences of these delays (including other potential delays), considering, inter alia, various force majeure claims that have not yet been fully investigated to date, are uncertain. The ultimate consequences of these delays (including other potential delays), considering, inter alia, various force majeure claims that have not yet been fully investigated to date, are uncertain. Projects Under Construction and in Advanced Development in Israel Set forth below is a description of OPC Israel’s projects under construction and in development. Hadera 2 In April 2017, OPC was authorized by the Israeli Government to seek authority for zoning of the land for a natural gas-fired power station on land owned by Infinya near the Hadera power plant. OPC Hadera Expansion Ltd. (“Hadera 2”), an OPC subsidiary, is party to an option agreement with Infinya to lease the relevant land, which was extended until the end of 2022. OPC intends to transfer Hadera 2 to OPC Power Plants, subject to approvals. In December 2022, Hadera 2 and Infinya signed an agreement for extending the project’s land lease period to a 5-year period. These plots of lands provide OPC with land that can be used with tenders but OPC would still require licenses to proceed with any projects on this land. In April 2024, the Israeli Government rejected the plan to construct a power plant on land adjacent to the power plant in Hadera 2. In June 2024, Hadera 2 petitioned the Israeli High Court of Justice regarding the reversal of the aforementioned government resolution. In December 2024, an order was handed down by the High Court of Justice, ordering the government to explain why the plan ought not to be submitted to the National Infrastructure Committee for further discussion, and alternatively, explain why the plan is not being re-assessed. A hearing subsequently took place in April 2025, after which the court proposed that the government discuss this issue again. Following discussions held regarding this petition, in August 2025, the Israeli government approved the plan to construct a natural gas-fired power plant on land owned near OPC’s Hadera power plant under the revised Regulation of Conventional Generation Units. OPC announced that it is preparing for the construction of Hadera 2 with an estimated capacity of approximately 850 MW (the “Hadera 2 Project”). OPC is taking action to sign project agreements, including engagement in the project, financing, construction, equipment and other agreements. Currently, given global schedule constraints for ordering equipment, OPC has entered into an equipment supply agreement with GE Vernova. OPC is seeking to obtain all the required approvals and permits (including securing connection to the grid) for the project. These steps by OPC involve, among other things, irrevocable undertakings and expenses involving third parties (including advance payments) which are exposed to uncertainty and development risks, considering that the advancement of the project and its execution are subject to conditions, which have not yet been fulfilled, such as the quota set by the EA, connection to the grid, obtaining permits and regulatory approvals, and completing material engagements associated with the project, the materialization or timing of which is uncertain. Accordingly, in the event that the conditions for financial closing of the project are not met the pre-construction costs are not expected to be reimbursed to OPC. OPC is negotiating the acquisition from Infinya of the interests in the land of the project and the Hadera Power Plant (instead of the lease agreement and the rental option agreement) for approximately NIS 450 million. OPC has preliminarily assessed the cost of construction of the Hadera 2 Project would be approximately NIS 4.5 billion to NIS 5 billion (approximately $1.4 billion to $1.6 billion). The construction of the project is expected to commence between June 2026 and June 2027. 56 Ramat Bekka Solar and Storage Project In May 2023, an OPC subsidiary won a tender of the ILA to develop renewable energy electricity generation facilities using photovoltaic technology co-located with storage with an option to acquire lease rights for land in Israel for construction in three areas in Neot Hovav Industrial Local Council, with a total area of approximately 2,270 dunams. The total amount of the bid was approximately NIS 484 million (approximately $133 million). Pursuant to the terms of the first tender, in the third quarter of 2023, 20% of the total consideration was paid in respect of an authorization and planning agreement. On June 30, 2024, OPC won an additional tender of ILA in connection with two sites with an aggregate area of about 1,617 dunams located adjacent to sites the subsidiary won in the previous tender (the “second tender”). OPC’s bids amounted to approximately NIS 890 million (approximately $236 million), in the aggregate, for the two areas in the second tender. The proximity to the sites to the site subject to the first tender is a major advantage and, subject to completing adequate development procedures, OPC is promoting a consolidated project which is expected by OPC to total approximately 550 MWh and estimated storage capacity of approximately 3,850 MWh (the “Consolidated Project”), and an estimated cost of approximately NIS 4.5 to 4.9 billion (approximately $1.2 to $1.3 billion), which is expected to result in certain cost savings, increasing the certainty as to the feasibility and characteristics of the projects, and positively impacting the conditions required for the execution of the projects and connection to the transmission grid. In accordance with the terms of the second tender, in September 2024, OPC’s subsidiary paid the ILA approximately NIS 178 million (approximately $49 million), which constitutes 20% of the total consideration in respect of the two plots of land in the additional tender, in connection with a three-year planning authorization agreement which may be extended by up to 12 months at the ILA’s discretion and subject to conditions. The amounts paid in respect of two tenders will not be refunded in the event the project’s development and planning procedures fail to develop into an authorized plan and lease agreements are not signed. In February 2024, the Israeli government resolved to authorize OPC Power Plants to prepare national infrastructure plans for a photovoltaic electricity generation project in connection with winning the first tender and to submit it to the National Committee for Planning and Building of National Infrastructures. In 2025, the Israeli government authorized the promotion of the plan in the National Infrastructures Committee with respect to the second tender’s land. In January 2026, the Consolidated Project’s plan was approved by the National Infrastructures Committee, and the plan was finally approved. After the plan’s final approval, OPC Power Plants will be given a period of 90 days to make the second payment of 80% with regard to the two tenders. The provisions of relevant regulations which OPC expects will apply to the Ramat Bekka project, may enable a substantial increase in the volume of storage in the project. The solar capacity is estimated at approximately 550 MW and the storage capacity in the project to up to approximately 3,850 MWh. The expected cost of the project is estimated at approximately NIS 5.2 billion (approximately $1.6 billion). OPC expects the construction phase to commence by the end of 2026, subject to completing all actions and all development, planning and licensing processes and obtaining the required approvals. 57 In January 2026, Ramat Bekka Solar entered into an EPC agreement with Afcon Holdings Ltd for approximately NIS 310 million in connection with a substation and a switching station with a capacity of approximately 970 MW, which will be used for converting voltage generated by the Ramat Bekka Project for the grid. The agreement includes customary provisions for agreements of this type, including collateral, payment execution terms and conditions, the work schedule, warranty periods, and limitations on the contractor’s liability. Ramat Bekka Solar may terminate the agreement prior the issue of the notice to proceed (NTP), and the contractor may terminate if no NTP had been issued within the period set in the agreement, subject to paying the contractor a certain amount. The commencement of the construction works is contingent on, among other things, financial closing of the Ramat Bekka project, obtaining required permits and regulatory approvals. OPC is working to advance the development of the project, including advancement of negotiations for entering into the project’s construction and equipment purchase agreements and is seeking the required approvals and permits. Power plant for Intel Israel facilities In March 2024, a subsidiary of OPC entered into a non-binding memorandum of understanding (the “Intel MOU”) with Intel, an existing customer of OPC, pursuant to which OPC’s subsidiary will construct and operate a power plant with a capacity of at least 450 MW (and up to 600 MW) (the “Intel Project”). The Project will supply electricity to Intel’s facilities in Gat, including an expansion of the facilities which is currently taking place, for a period of 20 years from the commercial operation date. The Intel MOU sets forth provisions regarding promotion of the development and planning of the Intel Project, acquisition of the rights to land, and collaboration of the parties to obtain the required permits in connection with the Intel Project. In addition, the Intel MOU includes arrangements regarding the tariff that will be paid to OPC’s subsidiary, which is based on rates that reflect a discount to the generation component tariff (based on the size and the Intel Project’s characteristics) and other provisions that will be included in a detailed agreement that the parties are expected to enter into. The parties are taking action to advance the development and planning of the project and to sign detailed agreements. During 2025, progress was made with respect to, among other things, receipt of a planning study, approval of access to the land and the required planning recommendation, and in March 2025 government consent was received for advancement of the plan. OPC is negotiating a PPA with Intel in connection with the project. OPC estimates that projected construction cost of the project will be in the range of about NIS 4.0 to NIS4.5 billion (approximately $1.3–$1.4 billion), depending on the size of the project. Subject to completion of the planning and development processes, the project is expected to reach the construction stage in the second half of 2027. Solar and storage projects OPC Israel is working to develop storage-incorporated solar projects in land owned by kibbutzim and moshavim, using photovoltaic technology in combination with storage, including agrivoltaic projects. OPC Israel has entered into agreements with holders of interests in the land (“Land Interest Holders”) where solar projects may potentially be constructed. Most of the agreements are option agreements under which OPC Israel has the right to develop and advance projects for the construction and operation of power generation facilities using solar energy co-located with storage facilities located on the ground or above and alongside agricultural crops. Generally, under the agreements, shortly prior to the financial closing, a joint special-purpose corporation will be established with the Land Interest Holders which will be held as required by law and will own the production facilit. OPC Israel is responsible for the development, licensing, management, financing, construction, maintenance and operation of the solar production facilities, and OPC will be given priority to purchase the electricity produced in the solar facilities. The agreements with the Land Interest Holders generally include payment to the Land Interest Holders for use of the land (including payments during the option period under agreed terms and conditions), and an option granted to the Land Interest Holders to participate – to a limited extent – in the project’s profits, while bearing the project costs and operating the project. Generally, such agreements include the management of the special-purpose corporation, arrangements regarding development expenses, representation on the board of directors of the special-purpose corporation and decision-making, arrangements regarding the financing of the project, arrangements for bearing various costs and collaboration arrangements for developing and constructing the project. 58 The solar electricity production activity of independent power producers and the supply of such electricity to customers is regulated and subject to licensing procedures. Agreements for the construction of solar facilities with an estimated aggregate capacity of approximately 0.5 GW and approximately 2,500 MW/h of storage capacity have been signed. In August 2025, the National Infrastructure Committee granted authorization to promote a scheme estimated at approximately 0.15 GW/h and approximately 0.75 GW/h of storage. The projects described above are under initial development stages and their completion, construction and operation are subject to obtaining all permits, to planning and licensing procedures and to ensuring connection to the grid, terms of engagement with major suppliers and lenders, final costs for development, construction and equipment, and completion of construction work. Accordingly, there is no certainty that all such projects will be executed, their characteristics of the projects, or their date of completion. In 2024, OPC entered into construction agreements with construction contractors and into equipment supply agreements and agreements for the maintenance of the engines and solar panels (as well as storage batteries) for some of the projects. Development of a natural gas project in partnership with Migdal In accordance with the relevant government resolution, OPC Israel and entities within the Migdal Insurance Company Ltd. group (“Migdal”) entered into an agreement under which a limited partnership was founded, in which OPC Israel and Migdal (indirectly) hold interests of 51% and 49%, respectively, with OPC Israel (indirectly) wholly owning the General Partner (the “Partnership with Migdal”), to develop, build and operate gas-fired power plants in an agreed area, through a special purpose corporate structure. OPC Israel will be given priority to purchase the power generated by the projects. The partnership provides for equity investment arrangements regarding development and construction expenses, and activity in the agreed area. These arrangements also include Migdal participating in projects outside the agreed area. In addition, the partnership agreement stipulated arrangements regarding management fees and development fees, restrictions on the transfer of rights, resolutions requiring a special majority, and information rights. Under certain circumstances, each party will have the right to convert Migdal’s share in the partnership with Migdal into a stake in OPC Israel, subject to certain conditions. In addition, the partnership signed an option agreement with Migdal for the lease of land (in which Migdal has interests) in the agreed area, which has the potential for constructing a gas-fired power plant. The option is for 9 years with early termination rights under certain conditions. The exercise of the option and the transfer of possession are subject to the fulfillment of certain conditions. If the option is exercised, a lease agreement will be entered into for a term equivalent to the land lease period with the ILA. The approvals required for the development in the option land have not yet been obtained, and there is no certainty that the conditions precedent to the engagement will be met, and that various actions, approvals and authorizations (including government authorizations), will be carried out and/or obtained within the expected timeframe or at all. 59 Rotem 2 In 2014, Rotem 2 won a tender for lease of plots on an area totaling approximately 55 dunams. The agreement is valid for term of 49 years from the date of the win in the tender, with an option for an additional lease term of 49 years. In August 2022, OPC received from the ILA an extension for the land development period under the lease agreement until March 9, 2025. OPC is working with the ILA to obtain an additional extension for the development period, which has not yet been approved and there is no certainty it will be given. OPC is looking into various alternatives to maximize the land’s business and planning potential, including construction of storage facilities. The advancement of the projects under development is consistent with OPC’s strategy with respect to expansion of its business activities in the electricity market in Israel. OPC is continuing its project initiation activities and is reviewing options while taking into account a number of factors and conditions including, among others, budget and execution processes, establishment of supplementary regulatory arrangements, the development plan of the transmission grid as well as other factors, including the ability to connect the projects to the transmission/distribution grid on time. At the same time, as part of OPC’s strategy, OPC takes steps to initiate and develop other projects, both gas-fired and renewable energy projects, by way of entering into agreements with landowners for the purpose of developing new projects or acquiring projects in various development phases. The expansion of OPC’s activities in Israel is subject to restrictions under the Market Concentration Law, and additional terms and conditions; accordingly, there is no certainty as to the completion of these projects. 60 United States OPC’s operations in the United States consist of the operations of CPV, which was acquired in January 2021 by an entity in which OPC indirectly holds an approximately 71% interest, and include: • Energy Transition – the operation of natural gas-fired power plants in the United States, which are part of the energy transition to efficient, reliable low-emission energy generation (referred to as “Energy Transition”); and • Renewable Energy – the development, construction and management of renewable energy projects and operation of renewable generation facilities (mainly solar and wind), through CPV Renewable LLC in which CPV Group holds 66.7% (“CPV Renewable”). In addition, CPV Group is engaged in additional activities, which include the development and construction of high efficiency natural gas power plants combined with future potential for carbon capture (subject to the development of this component) (“Low Carbon Projects”) and retail power supply which is intended to supplement the activity of CPV Group. CPV was founded in 1999 and since its establishment has developed power plants with an aggregate capacity of approximately 18 GW, of which approximately 5 GW consists of renewable energy and the remaining approximately 13 GW comes from Energy Transition and Low Carbon Projects. CPV holds interests in commercially operational power plants and power generation facilities it has developed, acquired and constructed over the years (using both natural gas-fired and renewable energy), as well as in a backlog of renewable energy and Low Carbon Projects. CPV Group’s share of generation capacity in commercially operational power plants is as follows: (i) in Energy Transition power plants (advanced combined cycle power plants), CPV Group’s share in entities holding in such power plants amounts to 2,241MW out of 5,303 MW (6 power plants) (including the increase in interests in already-owned plants acquired during 2025 and the acquisition of the remaining interest is Shore which closed in January 2026); and (ii) in Renewable Energy, CPV Group’s share in operational projects is 272 MWdc out of 408 MWdc in three solar power plants and 156 MW out of 234 MW in two wind power projects. CPV Group’s share of generation capacity in projects under construction is as follows: (i) in Low Carbon Projects, CPV Group’s share in entities holding the rights in the these power projects is 1,350 MW out of 1,350 MW in one Low Carbon project (which includes the acquisition of 30% interest in Basin Ranch from the other partner in the Basin Ranch project which closed in February 2026); and (ii) in Renewable Energy projects, CPV Group’s share is 24 MWdc out of 36 MWdc in the expansion of an existing solar project and 76 MW out of 114 MW in one wind energy project. The backlog of projects held by CPV Group which are currently in development includes: renewable energy projects and Low Carbon Projects in various development stages, with a total capacity of approximately 9,245 MW (excluding the carbon capture potential component), of which 7,210 MW is attributable to CPV Group’s. In October 2025, the Basin Ranch Project reached financial closing with the execution of the TEF Loan and the EPC agreement and commenced the construction stage. The carbon capture process is an additional, separate component of the natural gas projects currently under development/construction, which is subject to separate uncertainties and risks, and if implemented, is expected to be developed on a different timeline. In early 2023, CPV Group launched a retail energy platform called “CPV Retail Energy”. CPV Retail Energy serves as a retail electric provider for commercial and industrial customers in states within the PJM and NYISO markets. In 2024 and 2025 CPV Retail Energy grew its sales significantly. During 2024 and 2025, CPV Retail Energy executed contracts with approximately 440 and 540 customers, respectively, and its total sales volume increased from 0.5 to 1.5 TWh. CPV Retail Energy fixes the price of purchased power with hedging transactions. 61 Description of CPV operations CPV projects predominantly sell capacity and electricity in the PJM, NYISO and ISO-NE wholesale markets. Keenan (a consolidated subsidiary) is a party to a long term PPA with a utility company with respect to the entire revenue source of the project. Projects that are in development are expected to sell their energy, capacity and renewable energy credits in either the wholesale market or directly to customers through long-term purchase agreements. Generally, each Energy Transition project company that is not fully owned by CPV Group has entered into an agreement with all other owners of interests in the project (if any), for the establishment of a limited liability company. Each agreement sets forth each partner’s rights and obligations with respect to the applicable project (each, an “LLC Agreement”). Each LLC Agreement contains standard provisions for agreements of this type restricting the transfer of rights, including terms and conditions for permissible transfers, minimum equity percentage transfer requirements and rights of first offer. CPV Group is typically obliged to maintain at least a minimum ten percent equity ownership in a project company for up to five years after closing of construction financing. Each project company is governed by a board of managers selected by each of the partners in accordance with the relevant LLC Agreement. Certain material decisions typically require unanimous approval by all partners, including declaring insolvency, liquidation, sale of assets or merger, entering into or amending material agreements, incurring debt, initiating or settling litigation, engaging critical service providers, approving the annual budget or making expenditures exceeding the budget, and adopting hedging strategies and risk management policies. All active Energy Transition projects trade and participate in the sale of capacity, electricity and ancillary services in their respective ISO or RTO. Typically, CPV’s project companies conduct daily projections and planning for the next operating day. After making preparations in terms of purchasing adequate natural gas to support the expected electricity generation activity, as needed, bids are submitted to the Day-Ahead market. In addition, adjustments are made throughout the day for the actual operating day (the Real-Time market), which include purchases and sales of natural gas and optimizing generation output based on the Real-Time market price. In order to account for dynamic changes, natural gas projects enter into hedging agreements that are designed to set a fixed margin and reduce the impact of fluctuations in gas and electricity prices. CPV Group enters into interconnection agreements at the project level with transmission providers or electric utilities to establish substations, necessary electrical interconnection, system upgrades associated transmission services for the project’s commercial operations. In addition, CPV enters into natural gas interconnection agreements for its natural gas projects that provide for the design, construction, ownership, operation and management of natural gas pipelines to supply the project facility’s demand. CPV Group enters into agreements for the operation and maintenance of certain facilities. The consideration generally includes fixed annual management fees, a performance-based bonus and reimbursement of employment expenses, including, payroll and taxes, subcontractor costs and other costs as provided in the agreement. Generally, such agreements usually have an initial period of a few years from the construction completion date of the facility and include extension/renewal clauses, unless one of the parties gives notice of termination of the agreement. At the developmental stage, CPV’s project companies typically enter into third-party agreements with various experts for the provision of certain specialized services or in cooperation agreement intended to advance development of the project. Examples of such agreements include: (i) consulting agreements with environmental firms for land survey and tests, data collection, records analysis, conduct permit application work, permit reviews and other support services to engage with permitting agencies or participation in meetings with stakeholders and public officials, (ii) service agreements with engineering firms to support engineering reviews in the areas of civil, mechanical and electrical, and preparation of drawings to support permit and applications, (iii) consulting agreements with market consultants to support analysis related to power supply and demand and natural gas supply and demand, and (iv) joint development and cooperation agreements with strategic industry counterparties. Such joint development agreements are expected to provide for the issuance of equity or other rights to such counterparty in the project company and may be entered into in connection with the currently wholly owned Low Carbon pipeline project. 62 As part of the development and construction stages, some of CPV Group’s projects under development or construction have signed and/or are expected to sign certain agreements relating to the project, including PPAs and capacity agreements, RECs and in the framework of TEF Loan, which include sections relating to delays in commercial operation. If the delays are longer than certain periods, the other parties to the agreements may terminate such agreements, and the collateral provided under such agreements may be forfeited. The amount of collateral may increase or decrease pursuant to the terms of applicable agreements in connection with certain milestones being reached for the development projects. CPV Group’s project companies normally enter into various inter-company agreements with other CPV Group entities for the receipt of general services at the project level, with the exception of Fairview which is managed by another partner in the project. These inter-company agreements include asset management and energy management agreements. CPV Group provides general asset management and energy management services for power plants in the U.S. using renewable energy and energy produced using conventional technologies such as natural gas. The asset management services and energy management services are provided in exchange for a fixed annual fee, an incentive-based payment, and reimbursement of certain expenses, including expenses related to construction management services. Asset management services include, among other things: project management and compliance with regulations; supervision over project operation; project debt and credit management; management of agreements, licenses and contractual obligations; management of budgets and financial matters; project insurance and more. Energy management services include specific RTO or ISO-related functions, which include, among other things: assessment and advice on RTO/ISO standards, communicating with RTOs and ISOs, coordinating RTO/ISO projects; and preparing periodic regulatory reports. CPV Group has entered into a non-binding memorandum of understanding to explore a potential transaction which may involve increasing CPV Group’s holdings in certain operating natural gas power plants currently held by CPV Group, in exchange for certain rights in CPV Group. The non-binding memorandum of understanding also contemplates future cooperation to facilitate and structure such potential swap transaction. CPV Group has indicated its intention to continue examining potential transactions to increase its holdings in its energy transition power plants. CPV Projects Key Contracts Set forth below is a discussion of certain material contracts for each of CPV’s project companies that are commercially operational or under construction. Plants in Operation Fairview Fairview is party to the following agreements. • Gas Supply: a base contract for purchase and transmission of natural gas which provides for supply of natural gas at a quantity of up to 180,000 MMBtu per day at a price that is linked to market prices set forth in the agreement. Pursuant to the agreement, the gas supplier is responsible for transport of natural gas to the designated supply point and is permitted to transport ethane in lieu of natural gas for up to 25% of the agreed supply quantity. The agreement was renewed until March 31, 2027 without the option for the supplier to deliver ethane in place of natural gas. 63 • Maintenance: a maintenance agreement (MA) with its original equipment manufacturer, for the provision of maintenance services for the combustion turbines. In consideration for the maintenance services, Fairview pays a fixed and a variable amount as of the date stipulated in the agreement. The MA period is 25 years beginning in 2016 or ends earlier when specific milestones are reached on the basis of usage and wear and tear. • Hedging: a hedge agreement on electricity margins of the Revenue Put Option (“RPO”). The RPO is intended to provide CPV Group a minimum margin for the term of the agreement. Calculation of the amount for the minimum margin is determined for each contractual year, with the actual netting dates taking place every three months in respect of the respective partial amount and an annual adjustment is made to calculate the total annual margin for the year. The RPO has an annual exercise price that covers an exercise period of a fiscal year. To calculate the gross margin pursuant to the agreement, specific parameters are taken into account, such as utilization, heat rate, the expected generation levels, forward prices for electricity and gas, gas transmission costs and other specific project costs. The RPO expired on May 31, 2025. Towantic Towantic is party to the following agreements: • Gas Supply & Transmission: • an agreement for the guaranteed gas transmission of 2,500 MMBtu per day, at the AFT 1 Tariff. On June 1, 2024, the agreement was extended to March 31, 2027. The agreement renews automatically for periods of one year each time, unless one of the parties terminates the agreement; and • an agreement for the supply of gas, pursuant to which up to 125,000 MMBtu per day will be supplied at a price linked to market prices. The agreement commenced on April 1, 2023, and the delivery period was extended to March 31, 2027. • Maintenance: a services agreement with its original equipment manufacturer, for the provision of maintenance services for the combustion turbines. In consideration for the maintenance services, Towantic pays a fixed and a variable amount as of the date stipulated in the agreement. The agreement term is 20 years, beginning in 2016 or ends earlier when specific milestones are reached on the basis of usage and wear and tear. Maryland Maryland is party to the following agreements: • Gas Supply: an agreement for the supply of firm natural gas, pursuant to which up to 132,000 MMBtu per day will be supplied at a price linked to market prices. The term of the agreement commenced on November 1, 2024 and was extended until October 31, 2026. • Gas Transmission: a natural gas transmission agreement for guaranteed capacity of up to 132,000 MMBtu/d. The term of the agreement is 20 years from May 31, 2016, with an option for Maryland to extend it by an additional 5 years. • Maintenance: a services agreement with its original equipment manufacturer for the provision of maintenance services for the combustion turbines. In consideration for the maintenance services, Maryland pays a fixed and a variable amount as of the date stipulated in the agreement. The agreement period is 20 years beginning in 2014 or ends earlier when specific milestones are reached on the basis of usage and wear and tear. Shore Shore is party to the following agreements: • Gas Supply: an agreement for supply of natural gas. Pursuant to the agreement, the gas supplier supplies 120,000 MMBtu of gas per day at a price linked to the market price. The agreement is effective through October 31, 2026. 64 • Gas Transmission: two agreements with interstate pipeline companies for the use of their pipeline systems, the first of which has been operational since 2015 and the second of which became operational in late 2021. Pursuant to the agreements, natural gas connection and transmission services are provided to Shore by means of a single pipeline that is interconnected to two different interstate pipelines. The period of the gas transmission agreement for the pipeline is 15 years (until April 2030) for the pipeline agreement effective since 2015, with an option to extend the agreement for two additional ten year terms, The term for the pipeline agreement effective since 2021 is 20 years (until September 2041), with an option to extend annually. • Maintenance: an amended services agreement with its original equipment manufacturer for the provision of maintenance services for the turbines. In consideration for the maintenance services, Shore pays a fixed and a variable amount as of the date stipulated in the agreement. The agreement period is 20 years beginning in 2014 or ends earlier when specific milestones are reached on the basis of usage and wear and tear. Valley Valley is party to the following agreements: • Gas Supply: an agreement for the supply of natural gas of up to 127,200 MMBtu of natural gas per day at a price linked to the market price. Pursuant to the agreement, the supplier is responsible for transmission of natural gas to the designated supply point and the agreement expires on March 31, 2028. • Gas Transmission: an agreement with an interstate pipeline company for the licensing, construction, operating and maintenance of a pipeline and measurement and regulating facilities, from the interstate pipeline system for transmission of natural gas up to the facility. The supplier provides 127,200 MMBtu per day of firm natural gas delivery at an agreed price during a period ending March 31, 2033, with an option to extend by up to three additional five-year periods. Valley signed an agreement for the provision of transmission services (firm) of 35,000 MMBtu per day, for a period of 15 years ending on March 31, 2033, which can deliver gas from a different location into the firm transportation agreement referenced above. Valley also entered into an agreement for the provision of an additional 60,000 MMBtu per day of firm transmission service for a period from November 1, 2025 through March 31, 2028. • Maintenance: an agreement with its original equipment manufacturer for maintenance services for the fire turbines. The consideration includes fixed and variable amounts. The agreement period ends upon the earlier of: (i) completion of 132,800 equivalent base load hours; or (ii) 29 years from 2015. Three Rivers Three Rivers is party to the following agreements: • Gas Supply: two agreements for the supply of natural gas. The agreements supply 139,500 MMBtu in natural gas per day to the facility, from the operation date of the facility for a period of five years, and a reduced quantity of 25,000 MMBtu per day from the fifth year of operation of the facility and up to the tenth year. The price of natural gas delivered under these agreements is linked to the Day-Ahead electricity prices in the PJM Market. The agreements include an obligation to purchase such fixed volume of natural gas, with a right to resell surplus gas. • GSPA. Three Rivers entered into a Contract for Sale and Purchase of Natural Gas (the “GSPA”) on December 15, 2022. The GSPA requires the supplier to provide gas supply of up to 200,000 MMBtu/day at a price indexed to market. The agreement had an initial term until January 31, 2023. The agreement is automatically renewed month-to-month unless one of the parties elects to terminate. This agreement was terminated during 2025 and was replaced with a new agreement that currently runs through October 2026. 65 • Gas Interconnection: two connection agreements for transmission of gas: • One agreement is an interconnection agreement with an interstate pipeline company for transmission of natural gas. The agreement sets forth the responsibility of the parties in connection with the design, construction, ownership, operation and management of a pipeline as well as the connection and pressure equipment. Based on the agreement, Three Rivers bears the costs of all of the facilities. • The second agreement is an additional interconnection agreement with an interstate pipeline company for transmission of natural gas. As part of the agreement, the counterparty is responsible for the design and construction to connect to the existing pipeline. The counterparty to the agreement remains the owner of these facilities and operates them, and Three Rivers bears the construction and development costs. • Gas Transmission: an agreement for transmission of gas with an interstate pipeline company and its Canadian affiliate, for firm transmission of natural gas from Alberta, Canada to the facility. The agreements include capacity of 36.2 MMcf per day, at agreed prices. The term of the agreement is 11 years from the signing date of the agreement on November 1, 2020; the counterparty may extend the agreement for an additional year by means of prior notice of 12 months. • Maintenance: a services agreement with its original equipment manufacturer for the provision of maintenance services for the combustion turbines. In consideration for the maintenance services, Three Rivers pays a fixed and a variable payment. The agreement period is 25 years beginning in 2020 or ends earlier when specific milestones are reached on the basis of usage and wear and tear. Keenan Keenan is party to the following agreements: • PPA: a wind power energy agreement for sale of renewable energy. Pursuant to the agreement, the purchaser is to receive all of the electricity generated by the wind farm, credits, RECs, similar rights or other environmental allotments. The consideration includes a fixed payment. The period of the agreement is 20 years, ending in 2030. The purchaser is permitted, with proper notice, to extend the agreement for another five-year period, and to acquire an option to purchase the project at the end of the agreement period or renewal period at its fair market value, as defined in the agreement and pursuant to the terms and conditions stipulated therein. • Operation: a master services agreement and an operations agreement with its original equipment manufacturer for the operation, maintenance and repair of the wind turbines. The consideration includes fixed annual fees, performance-based bonus (or liquidated damages) and reimbursement of expenses for additional work. The agreement expires in February 2031. Mountain Wind Mountain Wind holds 100% in each of the four wind projects: (i) CPV Saddleback Ridge Wind, LLC; (ii) CPV Canton Mountain Wind, LLC; (iii) CPV Beaver Ridge Wind, LLC; and (iv) CPV Spruce Mountain Wind, LLC. Mountain Wind is party to the following agreements: • Maintenance: a master services agreement for the management and maintenance of the four wind facilities (Saddleback Ridge, Canton Mountain, Beaver Ridge, Spruce Mountain) entered into by Mountain Wind. Staff is shared between the four projects. At all projects except for Beaver Ridge, the services agreement applies only to work outside the scope of the turbine services which is performed by the original equipment manufacturers. At Beaver Ridge, where there is no agreement with the original equipment manufacturer, the agreement also covers the direct maintenance of the wind turbines. The agreement commenced on April 5, 2023, with an initial two year term and was extended through May 2, 2027. • Other contracts: The projects have entered into contracts to sell 100% of the electricity and RECs, under separate contracts (PPAs) with local utility companies and councils, generally for a period of the next 15 to 20 years from the acquisition of the projects by CPV, with most of the capacity sold under separate contracts for the next 12 years from the acquisition of the projects by CPV (the periods of the contracts may change according to termination clauses in each agreement). 66 Maple Hill Maple Hill is party to the following agreements: • Tax Equity Partner. In May 2023, CPV entered into an investment agreement with a tax equity partner in the Maple Hill project. In consideration for its investment in the project corporation, the tax equity partner is expected to receive most of the project’s tax benefits, including ITC at a higher rate of 40% (in accordance with the IRA), and participation in the distributable free cash flow from the project (at single digit rates and on a gradual basis as set out in the investment agreement). In addition, the tax equity partner is entitled to participate in the project’s loss for tax purposes; in the first few years, the tax equity partner’s share in such taxable income or loss for tax purposes is high. At the end of 6 years from the COD, the tax equity partner’s share in such taxable income decreases significantly, and CPV has the option to acquire the tax equity partner’s share in the project corporation within a certain period. The agreement includes a guarantee provided by CPV, and an undertaking to indemnify the tax equity partner in connection with certain matters. Furthermore, the tax equity partner has certain veto rights, among other things, in respect of the creation of liens on the Maple Hill project corporation’s assets or the entry of the Maple Hill project corporation into additional material agreements. In December 2023, the tax equity partner completed its entire investment in the project in a total aggregate amount of approximately $82 million. • SREC. An agreement with an international energy company for the sale of 100% of the SRECs generated in the project through 2027 to an international energy company. CPV provided collateral for its obligations under the agreement, which include delivery of SRECs generated by the project. • Virtual PPA. An agreement with a third party for the sale of 48% of the total generated electricity, where the electricity price calculation is based on financial netting between the parties for 10 years from the commercial date of operation. In accordance with the agreement, a net calculation will be made of the difference between the variable price that Maple Hill receives from the system operator and which is published (the spot price) and the fixed price set with a third party. CPV Group provided collateral for its obligations under the agreement, which include making certain payments to the other party as part of the settlement of the virtual PPAs. The agreement includes an option to transition to a physical PPA with a fixed price on fulfillment of certain terms and conditions, which have yet to be met. Stagecoach Stagecoach is party to the following agreements: • Energy Sale Agreement (non-firm). In March 2022, Stagecoach entered into an agreement to sell 100% of non-firm energy to a utility company. The utility company is to receive all of the energy and ancillary services produced by Stagecoach. The agreement excludes tax attributes arising from the ownership of the solar project and any environmental attributes generated by Stagecoach. The consideration is based on the hourly avoided energy rate for each hour of generation up to a maximum energy output as defined in the agreement. The agreement is for a period of 30 years from the commercial operation date of Stagecoach. The agreement provides for sale to a global utility company of 100% of the project’s SRECs, as well as a hedge covering the entire electricity price of the quantity that shall be produced and sold to the utility company, at a fixed price, for a period of 20 years from the date of commercial operation of the project • Agreement to sell renewable solar energy credits. In April 2022, Stagecoach entered into an agreement with a global company to sell 100% of the renewable solar energy credits produced by the solar project, along with a full hedge of the electricity price of the energy that will be generated and sold under the agreement with the utility company, at a fixed price for 20 years from the commercial operation date. Tax Equity Agreement. On May 13, 2024, Stagecoach entered into a tax equity agreement with a tax equity partner for an investment in respect of the Stagecoach project, for a total amount of approximately $52 million, which was completed on its signing date, after the project reached commercial operation in the second quarter of 2024. As of its completion date, the tax equity partner in the project funded an investment of approximately $43 million with the remainder to be funded over the term of the agreement as a function of the project’s production pursuant to the terms and conditions set forth in the agreement. In consideration for its investment in the project, the tax equity partner is expected to benefit from most of the project’s tax benefits, including a PTC, which awards a tax benefit for each kWh generated using renewable energy over a 10-year period, and will receive a portion of the distributable cash flow from the project (gradually, and at rates and for periods set in the agreement). Furthermore, the tax equity partner is entitled to most of the project’s taxable income or loss for tax purposes subject to certain limitations. At the end of 9.5 years from the completion date, the tax equity partner’s share in such taxable income and tax benefits decreases significantly and CPV Group will have the option to acquire the tax equity partner’s share in the project in accordance with the terms and conditions set forth in the agreement. The agreement includes a guarantee provided by CPV Group and an undertaking to indemnify the tax equity partner in connection with certain matters. Furthermore, the tax equity partner has certain veto rights, among other things, in respect of the creation of certain liens on the project’s assets or the entry of the project company into additional material agreements. 67 Backbone CPV Group is party to the following agreements: • EPC. In June 2023, Backbone entered into an EPC agreement with a construction contractor in respect of the construction of Backbone project which was amended and restated in October 2025 with respect to the construction of the expansion of the project. In accordance with the agreement, the contractor is required to plan, purchase, install, build, test, and operate the solar project in full, on a turnkey basis. The consideration in the EPC agreement in the amount of $193 million, of which approximately $183 million was paid in accordance with the milestones set in the EPC agreement for the main part of the Backbone project (which achieved commercial operations on November 26, 2025). The remaining costs to be paid are for close out items that will be paid in the coming months and the cost of the expansion in the amount of $35 million will be paid according to milestones set for the expansion of the project. • Renewable Solar Energy Credits. In 2023, Backbone entered into an agreement with a global company to sell approximately 81% of the renewable solar energy credits (which are valid until 2035) produced by the main part of the solar project (with capacity of 179 MW), along with a hedge of the electricity price of the energy that will be generated and sold to PJM, at a fixed price for 10 years from the commercial operation date. The balance of the project’s capacity will be used for supply to active customers, retail supply of electricity of CPV Group or for sale in the market. CPV Group provided collateral to secure its obligations in the agreement, which include an agreement to make certain payments to the other party if certain milestones (including commencement of activities) in the project are not met according to a specific schedule. • Tax Equity Agreement. On October 10, 2024, Backbone entered into a tax equity agreement with a tax equity partner in respect of the main part of the project (with capacity of 179 MW) for a total amount of approximately $120 million. Approximately 20% of the tax equity partner’s investment in the project was provided on the project’s mechanical completion date of October 2025, and the remaining balance was provided on the commercial operation date on December 19, 2025. In October 2025, an agreement was signed to join the 36 MWdc expansion of the project to the tax equity partner agreement for approximately $19 million, on conditions similar to those of the original agreement. In accordance with the provisions of the agreement, 100% of the tax equity partner’s investment in the project will be provided on the commercial operation date, subject to the terms and conditions set forth in the agreement. In connection with its investment in the project, the tax equity partner is expected to benefit from most of the project’s tax benefits, including the project’s taxable income or its loss for tax purposes, an ITC, which is based on the investment in the project’s compliance with the required conditions, subject to certain restrictions and for periods as set in the agreement, and to participate in the distributable cash flow from the project (gradually, and at rates and for periods set in the agreement). At the end of 5 years from the commercial operation date, the tax equity partner’s share in such taxable income and tax benefits decreases significantly, and CPV Group will have the option to acquire the tax equity partner’s share in the project within a certain period and in accordance with the agreement. The agreement includes a guarantee provided by CPV Group, and an undertaking to indemnify the tax equity partner with respect to certain matters. Furthermore, the tax equity partner will be entitled to rights in the Project and to certain veto rights, among other things, in respect of the creation of certain liens on the project company’s assets or the engagement of the project company in additional material agreements. In addition, the tax equity partner may be entitled to an under-delivery fee at a rate and under conditions set forth in the agreement. 68 Projects under Development or Construction Rogue’s Wind CPV is party to the following agreements: • Rogue’s Wind Energy Project. In April 2021, an agreement was signed for the sale of all the electricity, and the project’s other economic attributes (including RECs), benefits relating to availability and accompanying services. The agreement may be adjusted to updated factors of the project. The agreement was signed for a period of 10 years from the commercial operation date. CPV Group has provided collateral for securing its liabilities under the agreement, including agreeing to make of certain payments to the other party if certain milestones (including the commencement of date of the activities) in the project are not met in accordance with a specific timetable. • EPC. In August 2024, Rogue’s Wind signed an EPC agreement with an international contractor and an equipment procurement agreement. Pursuant to the agreement, the contractor is to design, engineer, procure, install, construct, test, and commission the wind project on a turnkey, guaranteed-completion-date basis. In August 2024, Rogue’s Wind signed an EPC switchyard agreement with an international contractor. Pursuant to the agreement, the contractor is to engineer, procure, install, construct, test, and commission the electrical switchyard on a turnkey, guaranteed-completion-date basis. The total consideration to be paid to the contractor is a fixed amount, subject to change orders, payable under a milestone schedule. The total consideration for both EPC agreements is expected to total approximately $113 million. The project is located on a former coal mine and, therefore, it is expected to be entitled to enlarged tax benefits of 40% in accordance with the IRA. In August 2025, CPV Group signed an agreement with a tax partner (Equity Tax) in an ITC format in respect of about 40% of the cost of the project (approximately $163 million) and use of the tax credits that are available to the project (subject to appropriate regulatory arrangements) on terms that are customary for agreements of this type, similar to Backbone (including provision of a guarantee by CPV Group for certain liabilities). • Wind Turbine Supply Agreement. In August 2024, Rogue’s Wind signed a wind turbine supply agreement for the purchase of wind turbines with an international supplier. The total cost of the agreement is approximately $139 million. • Tax Equity Agreement. The project is located on a former coal mine and, therefore, it is expected to be entitled to enlarged tax benefits of 40% in accordance with the IRA. In August 2025, CPV Group signed an agreement with a tax partner in an ITC format relating to about 40% of the cost of the project (approximately $160 million) and use of the tax credits that are available to the project (subject to appropriate regulatory arrangements) on terms that are customary for agreements of this type, similar to the terms of the tax equity agreement entered into by Backbone (including provision of a guarantee by CPV Group for certain liabilities). Low Carbon Projects Basin Ranch Project CPV is party to the following agreements: 69 • GEV Equipment Agreement. Basin Ranch signed an agreement with the equipment supplier (GE Vernova) that was until February 2026, a partner in the project for the acquisition of the main equipment for the project (the “GEV Equipment Agreement”). The GEV Equipment Agreement includes specifications regarding the power generation equipment for the Project (H Class technology) including 2 gas turbines and 2 steam turbines. Such equipment agreement includes, among other things, the dates and conditions for supply and payment, the manufacturer’s warranty and specifications with respect to the equipment, and certain guarantees and liability provisions (subject to caps). • EPC Agreement. On October 28, 2025, Basin Ranch entered into an Engineering, Procurement and Construction Agreement (“EPC Agreement”) with a U.S. based power plants construction company with respect to the construction of the Basin Ranch project. Under the EPC Agreement, the contractor has committed to provide engineering and construction of the full facility including integration of the GEV equipment and procurement of the remainder of the equipment (which is not purchased under the GEV Equipment Agreement). The EPC agreement includes customary terms and commitments customary in transactions of this type, such as the contractor’s commitment to completion schedule; warranty period; performance tests; various guarantees to secure the contractor’s obligations and performance values under the agreement; liquidated damages for delay (with applicable caps); standard grounds for termination of the agreement; insurances; liability of the contractor limited by caps. The main equipment for the project is supplied under the GEV Equipment Agreement. The consideration under the EPC Agreement and GEV Equipment Agreement will be paid over time in accordance with the milestones set in each agreement and is expected to total, in aggregate for both agreements (including additional equipment contracts), to approximately $1.4 billion. Both the EPC Agreement and GEV Equipment Agreement include fixed consideration and additional variable consideration payable by the project company for relevant tariff costs. • Maintenance Agreement. Basin Ranch entered into an agreement with the original equipment manufacturer for maintenance services for the Basin Ranch project’s combustion turbines. The agreement will become effective on the Basin Ranch project’s Substantial Completion date (as defined in the relevant agreement) and will expire on the earlier of: (1) 25 years from its effective date; or (2) achievement of defined milestones based on equipment usage and wear. In accordance with the agreement, Basin Ranch will pay consideration comprised of a fixed component and a variable component. The expected cost over the term of the agreement, commencing on the Commercial Operation Date, is estimated at an average annual cost of approximately $11 million (all-in-costs) per year. • Purchase Agreement. On October 28, 2025, CPV Group (through wholly owned subsidiaries), entered into a purchase agreement with GE Vernova, the remaining partner in the Basin Ranch project (the “Seller”), for the acquisition of the Seller’s remaining 30% ownership interest in the Basin Ranch project (the “Purchase Agreement”) which closed in February 2026, following fulfillment of conditions. The amount required in connection with the acquisition under the Purchase Agreement totals approximately $371 million. According to the Purchase Agreement, CPV Group is to provide such amount (through combination of cash and letters of credit, as applicable, and subject to the Purchase Agreement) on several dates starting from TEF Loan closing and in the interim period (approximately $65 million), closing of the acquisition under the Purchase Agreement (approximately $226 million primarily representing the provision of the equity required in connection with the TEF loan, as mentioned above) and during the construction of the Basin Ranch project (approximately $80 million, payable in four equal installments of approximately $20 million each, commencing in 2026). The conditions precedent mainly include replacement of the Seller’s collateral and amounts in connection with the TEF Loan. In January 2026, the Leumi Financing was increased by $130 million for the purpose of funding the acquisition. On February 2, 2026, the transaction under the Purchase Agreement closed following funding, through a combination of cash and letters of credit, of the amounts required in accordance with the Purchase Agreement. 70 The acquisition under the Purchase Agreement resulted in consolidation of the Basin Ranch project in CPV Group’s financial statements and accordingly in OPC’s financial statements. • Equity Contribution Agreement. As part of the TEF Loan, direct and indirect equity holders of Basin Ranch project provided the entire equity required for the project relative to their holdings as of the Financial Closing date. CPV Group (70%) provided a total amount of approximately NIS 1.5 billion (approximately $470 million), of which approximately NIS 1 billion (approximately $300 million) was provided by way of a loan from Bank Leumi, and approximately NIS 562 million (approximately $170 million) was provided by OPC through an equity bridge loan to cover the period until the equity investment process with the additional partners at OPC Power was completed which was completed in March 2026. To provide the bridge loan, OPC used some of the funds raised in the OPC share issuance in June 2025. Moreover, additional collateral in connection with the project was provided by the project’s interest holders as part of the TEF Loan’s Financial Closing. CPV Group’s share (70%) in the additional collateral, which was provided by way of letters of credit, totals approximately NIS 446 million (approximately $135 million). Equity Investment in CPV Renewables On August 16, 2024, subsidiaries of CPV Group entered into agreements with Harrison Street, a U.S. private equity fund in the field of infrastructure which provide for the Investor to invest $300 million (the “Total Investment”) in CPV Renewables for 33.33% of the ordinary equity interests in CPV Renewables. On November 13, 2024, the transaction was closed. On the closing date, the Investor funded $200 million of the $300 million Total Investment and 33.33% of the ordinary equity interests in CPV Renewables was issued to the Investor. Upon completion of the transaction, CPV Renewables was no longer consolidated and it is considered an associate of OPC and the remaining $100 million of the Total Investment was funded as agreed by September 30, 2025. A shareholders agreement which became effective upon closing of the transaction, sets forth agreements between the Investor and CPV which includes provisions governing, among other things: (i) board composition – the initial board composition as of closing shall comprise four members (two directors appointed by each of CPV and the Investor) – whereby votes of board members is based on the equity interest of the appointing shareholder; (ii) transfer restrictions, subject to agreed terms and exclusions; and (iii) actions and decisions that require super majority approval (which require the vote of the Investor’s appointed board members). The agreement also provides that CPV’s renewable activities will be conducted through CPV Renewables. The agreement further provides that CPV will provide development and asset management services to CPV Renewables pursuant to long term service agreements, which include, among other things, an obligation of CPV to provide sufficient resources and qualified personnel for this purpose. Projects in Various Stages of Development CPV currently has renewable energy projects and natural gas-fired power plants in advanced stages of development. Additional Activities CPV Group is engaged in additional activities, including the development and construction of Low Carbon Projects currently in the PJM and ERCOT markets and retail power supply to commercial and industrial consumers. Construction and Development of Low Carbon Projects Low Carbon Projects are based on the development and construction of natural gas-fired power plants with carbon capture potential which is a separate component developed in separate development and/or operational stages, based on various considerations, such as relevant market and location, economic and commercial considerations, development progress, technical and engineering factors and/or other considerations, which may result in the different schedule for, or suspension of development of, the carbon capture component. 71 Natural gas power plant project (with carbon capture potential) under construction In October 2025, the Basin Ranch project reached financial closing with the execution of the TEF Loan and the EPC agreement, and commenced the construction stage. For details regarding Basin Ranch, see above. Low Carbon Projects Pipeline in Development CPV is developing three Low Carbon Projects in development in Ohio and West Virginia. The table below sets forth certain information relating to such projects. Project State Regulated Market MW(1) Development Stage Rate of Holdings Share of CPV Group Shay WV PJM 2,100 Early 70 % 1,470 Oregon OH PJM 1,475 Early 100 % 1,475 Walker OH PJM 1,450 Early 100 % 1,450 Total 5,025 4,395 (1) MW is presented based on operation as a natural gas power plant assuming operation of the power plants without carbon capture component. CPV Group’s share in such Energy Transition projects is 70% for the project in West Virginia and 100% for the projects in Ohio. CPV Group believes the projects are in areas where the burying of carbon could potentially be geologically feasible based on preliminary analysis performed by third party contractors and subject to development. For the Shay project in West Virginia, CPV Group acquired land rights and has accelerated its advancement of the project’s development, including the processes for licensing and PJM grid interconnection, and has secured significant equipment. CPV Group has signed an agreement for major electrical equipment and a turbine (slot) reservation agreement with a global equipment supplier. The agreement provides for payment of non-refundable advance deposits in the total amount of millions of dollars. CPV Group‘s initial estimate of the cost of the power plant (100%) is approximately $4 billion. In addition, as part of the development activities, CPV Group is acting to, among other things, advance the appropriate commercial outline for each of the projects under development. In connection with the Shay project, CPV Group is exploring potential commercial structures, such as gas net back arrangements, subsidized loan programs such as the U.S. Department of Energy’s Section 1706 loan program, which was reoriented by the OBBBA to support a broader range of energy generation technologies, and PJM capacity initiatives (such as the CIFP process to balance reliability with large load growth, if adopted). At this stage, these options are in the preliminary stage of consideration, and there is no certainty that such options (or any of them) will be available or applicable to the Shay project, or as to their terms. Should the projects be executed, they may be eligible for tax benefits under applicable law, although there is no certainty as to such eligibility or the extent of such benefits. The construction of the projects, similar to the Basin Ranch project in Texas, is subject, among other things, to the fulfillment of various conditions, including securing interconnection within a reasonable timeline and at reasonable cost, regulatory processes, obtaining approvals, licensing procedures, completing the development of technological capabilities, securing financing and a commercialization outline, as well as the approval of the authorized bodies of OPC and CPV Group. CPV has commenced the licensing processes, performed surveys and acquired land rights in Texas and West Virginia. In October 2025, CPV Group signed an agreement for the sale of rights in the Mason Road project, an early development stage project located in Michigan having a capacity of approximately 1.4 GW (CPV Group’s share of which is 70%), in exchange for immaterial consideration. In light of such sale agreement, the project is not included in the above table. The IRA currently extends and expands the production tax credits available for carbon dioxide sequestration and/or use. For electricity generating facilities that install carbon capture technologies with the capacity to capture 75% or more or baseline carbon dioxide production, this production tax credit is available for the first 12 years after placement in service if the applicable electricity generation facility captures at least 18,750 metric tons of carbon dioxide per annum. The base credit amount is $17/metric ton of carbon dioxide that is captured and sequestered or injected for enhanced oil recovery or utilized in another production process. Like the Investment Tax Credits (the “ITC”) and Production Tax Credits (“PTC”) for renewable energy, the carbon capture PTC can be increased if the project meets relevant wage and apprenticeship requirements. The maximum credit is $85/metric ton. In addition, the tax credit is eligible for direct pay for up to the first five years for carbon capture equipment placed in service after December 31, 2022. 72 Retail Power Supply to Commercial and Industrial Consumers In early 2023, CPV Group established a retail power supply activity through CPV Retail Energy. CPV Retail Energy relies on the wholesale market and CPV’s generation assets to support commercial and industrial businesses meet their energy needs and sustainability goals. During 2024 and 2025, CPV Retail Energy executed contracts with approximately 440 and 540 customers, respectively and its total flowed sales volume increased from 0.5 to 1.5 TWh, respectively. CPV Retail Energy fixes the price of purchased power with hedging transactions. In connection with the retail power supply activity, a corporate guarantee was granted to guarantee CPV Retail Energy’s obligations. CPV Retail Energy offers customers energy, including renewable energy, to help meet customers’ energy goals and offers contract terms that range from one to five years (with the typical term being approximately two years). CPV Retail Energy utilizes a standard electricity supply agreement that allows customers to select whether standard cost components, such as energy or ancillary services, are fixed at a price or passed through at cost to the customer. In August 2025, CPV Retail entered into an accounts receivable (A/R) financing agreement for a term of three years with the total commitment of up to $25 million subject to eligible trade receivables and customary terms. As of December 31, 2025, CPV Retail had initial borrowings and posted collateral for an immaterial amount to OPC. OPC’s Customers Israel In Israel, OPC’s active power plants (except for Zomet) enter mainly into PPAs with private customers. Most of the bilateral sales to private (non-household) consumers in conventional technology are conducted in Israel at prices based on the DSM Tariff published by the EA, with a certain discount given in respect of the generation component. When an independent power producer and a private customer enter into a PPA, the independent power producer becomes the supplier for that customer’s meters for which the PPA was signed (however, no physical connection exists between the producer and the customer; rather, the electricity generated by the producer is transferred to the IEC’s grid, which supplies electricity to the private customer from the grid). In the event that a producer does not produce electricity for its customers, it purchases electricity from another conventional independent producer or from the System Operator for sale to a private customer. OPC aims to manage electricity sales from the Rotem, Hadera and Gat power plants and the virtual supply activity (also through production facilities on consumers’ premises) in a manner intended to maximize synergies. Some power plants operate under a unified supply model allowing for electricity generated in OPC’s facilities to be sold to end customers through an OPC subsidiary holding a tailored supply license. In connection with Zomet power plant, its entire capacity of the Zomet allocated to the System Operator under a fixed capacity arrangement and Zomet is not permitted to enter into PPAs with private customers. PPAs. Except for Zomet, OPC sells energy in Israel through PPAs with the average weighted remaining agreement term is approximately 8 years (subject to the option for early termination or extension as set out in the agreement with each customer). Rotem’s PPA with the IEC, which extends for a 20-year term from COD of Rotem, provides Rotem with the option to allocate and sell the generated electricity of the power station directly to private customers. Rotem has exercised this option and sells all of its energy and capacity directly to private customers (i.e., customers other than the IEC). Total revenue from electricity sales to private customers as a percentage of OPC’s total revenues from electricity sales in the operating segment in Israel in 2025 was 86%, compared with 84% in 2024. The difference between the rate of the sales and 100% is due to sale of electricity and availability revenues to the System Operator (the IEC or Noga). The main customers in this operating segment include commercial real estate companies, industrial enterprises, academic institutions, etc. Certain customers are party to customer-sited generation facility “build and operate” agreements with OPC, to enable combined electricity supply from the generation facility and the relevant power plant. As part of the engagements with OPC for construction of the generation facilities on consumers’ premises as described above, PPAs were entered into with customers, usually for a period of 15 to 20 years from the generation facility’s commercial operation date (subject to early termination provisions). Rotem’s PPAs. Rotem’s regulatory framework differs from the general regulatory framework for IPPs, as described above. According to Rotem’s PPA with the IEC, Rotem may sell electricity in one or more of the following ways: • Capacity and Energy to the IEC: according to Rotem’s PPA with the IEC, Rotem is obligated to allocate its full capacity to the IEC. In return, the IEC shall pay Rotem a monthly payment for each available MW, net, that was available to the IEC. In addition, when the IEC requests to dispatch Rotem, the IEC shall pay a variable payment based on the cost of fuel and the efficiency of the station. This payment will cover the variable cost deriving from the operation of the Rotem Power station and the generation of electricity. • In addition, subject to the provisions of Rotem’s PPA with the IEC, in the event of a sustained failure in natural gas supply, Rotem is expected to be entitled to make the capacity of the Rotem Power Plant to the System Operator in exchange for a refund in respect of the difference between the cost of energy generation using diesel fuel and Rotem’s generation cost using gas for the energy generated. • Sale of energy to end users: Rotem is allowed to inform the IEC, subject to the provision of advanced notice, that it is releasing itself in whole or in part from the allocation of capacity to the IEC, and extract (in whole or in part) the capacity allocated to the IEC, in order to sell electricity to private customers pursuant to the Electricity Sector Law. Rotem may, subject to 12-months’ advance notice, re-include the excluded capacity (in whole or in part) as capacity sold to the IEC. Rotem informed the IEC, as required by Rotem’s PPA with the IEC, of the exclusion of the entire capacity of its power plant, in order to sell such capacity to private customers. Since July 2013, the entire capacity of Rotem has been allocated to private customers. Rotem’s PPA with the IEC includes a transmission and backup appendix, which requires the IEC to provide transmission and backup services to Rotem and its customers, for private transactions between Rotem and its customers, and the tariffs payable by Rotem to the IEC for these services. Moreover, upon entering a PPA between Rotem and an individual consumer, Rotem becomes the sole electricity provider for this customer, and the IEC is required to supply power to this customer when Rotem is unable to do so, in exchange for payment by Rotem according to the tariffs set by the EA for this purpose 73 Hadera’s PPAs. In September 2016, Hadera entered into an agreement with the IEC to purchase energy and provide utility services (PPA). As part of the IEC Reform, the IEC’s obligations under the agreement were assigned to Noga, such that as of December 2021, except with respect to specific provisions and duties concerning the power plant’s connection to the grid and measurement and metering arrangements between the IEC and Hadera, which shall continue to apply. Pursuant to the PPA, Hadera undertook to sell to the IEC energy and ancillary services, and the IEC undertook to sell to Hadera utility services and power system operating services, including backup services. The agreement will remain in effect until the end of the period in which Hadera is permitted to sell electricity to private consumers as set forth in the supply license, regarding the utility and system management services, and up to the end of the period in which it may sell energy to the System Operator. The agreement also includes provisions governing the connection of the Hadera Power Plant to the electrical grid, as well as provisions covering the design, construction, operation and maintenance of the Hadera Power Plant. The agreement also includes an undertaking by Hadera to meet the capacity and reliability requirements provided in its license. Hadera has a long-term PPA with Infinya, as part of which Hadera provides the entire electricity and steam needs of Infinya plants (the “Infinya plants”), which are located close to the Hadera power plant. The Hadera power plant has a direct power line to the Infinya plants. Under the agreement, Hadera is to exclusively supply electricity and steam to the Infinya plants for 25 years from the Hadera COD. The tariff paid by Infinya for the electricity purchased by it for the agreement term is based on the DSM Tariff, with a discount on the generation component, plus a fixed payment in respect of the size of the connection. agreement sets the price of steam, which is primarily linked to Hadera’s gas price, as set forth in the gas supply agreements signed by Hadera and in accordance with Infinya’s annual steam consumption. In accordance with the agreement, Infinya is committed to pay for a minimum annual quantity of steam, subject to the adjustments set forth in the agreement, even if it consumes a smaller quantity (a take-or-pay mechanism). Hadera is committed to a specific capacity level and to additional conditions with respect to the supply of electricity and steam (with the exception of a lack of capacity caused by certain events set in the agreement, which are not under its control). Zomet’s PPAs. In January 2020, Zomet entered into a PPA with the IEC (the “Zomet PPA”). In October 2020, Rotem received notice of assignment by the IEC to the System Operator which was subsequently reassigned to Noga. The term of the Zomet PPA is 20 years after the power plant’s COD. According to the terms of the Zomet PPA, (i) Zomet sells energy and capacity to the IEC and the IEC provides Zomet infrastructure and management services for the electricity system, including back-up services, (ii) all of the Zomet plant’s capacity is sold pursuant to a fixed availability arrangement, which will require compliance with criteria set out in relevant regulation , (iii) the plant will be operated pursuant to the System Operator’s directives and the System Operator will be permitted to disconnect supply of electricity to the grid if Zomet does not comply with certain safety conditions and (iv) Zomet will be required to comply with certain availability and credibility requirements set out in its license and relevant regulation , and pay penalties for any non-compliance. Zomet plant’s entire capacity is allocated to the System Operator pursuant to the terms of the Zomet PPA, and Zomet will not be permitted to sign agreements with private customers unless the electricity trade rules are updated. Pursuant to the generation license, Zomet is entitled to receive capacity payments in accordance with a capacity tariff from the System Operator of between 5.7 and 6.5 agorot per kilowatt hour, subject to the number of ignitions. In addition, Zomet is entitled to an electricity and gas tariff based on the generation and purchase cost and pursuant to the terms of the generation license and relevant EA regulation. Gat’s PPA. In October 2016, the Gat Power Plant and the IEC entered into an agreement for the purchase of capacity and energy and the provision of utility services. As part of the IEC Reform, IEC’s duties and undertakings under an agreement were assigned to Noga, as from December 2021, except with regard to certain provisions and duties which concern the connection of the power plant to the grid and arrangements pertaining to measurement and metering, which will continue to apply between the IEC and the Gat Power Plant. Pursuant to the PPA, the Gat Power Plant undertook to sell to the IEC energy and ancillary services, and the IEC undertook to sell to Gat the utility services and power system operating services, including backup services. The agreement shall remain in effect: (1) with respect to the infrastructure and system management services, until the end of the period in which the Gat Power Plant may sell electricity to private consumers, as set forth in the supply license; (2) with respect to energy and ancillary services purchases, until the end of the period in which the Gat Power Plant may sell energy to the System Operator, as set forth in the generation license; and (3) with respect to available capacity and energy purchases in the period during which the production unit does not meet the cogeneration conditions – as set forth in the Cogeneration Regulations. The agreement also includes provisions governing the power plant’s connection to the electrical grid, as well as provisions covering the design, construction, operation and maintenance of the Gat Power Plant. In addition, the Gat Power Plant undertook to meet the capacity and reliability requirements provided in its license. Agreements for sale to household consumers and SMBs and further expansion of activity in the supply to household consumers and SMBs market. In 2024 and 2025, Rotem entered into agreements with large retailers (the “Resellers”) for the purpose of selling power to the Marketers’ consumers, which are household consumers and SMB. The agreement will allow the diversification of OPC’s customer mix. According to the agreements, Rotem will supply electricity at maximum quantities and under the conditions as defined therein, to Resellers’ customers, who will engage with OPC with OPC and the relevant Reseller in an agreement for the supply of electricity by OPC under the conditions and maximum scope defined. OPC is required to supply the electricity and is entitled to payment from the relevant Reseller in accordance with the quantity of electricity consumed by Resellers’ consumers and in accordance with the tariffs prescribed in the agreement. The agreements do not include an undertaking by the Resellers to purchase a minimum quantity of electricity or to enroll a minimum number of consumers. Rather they include an undertaking by the Resellers to assign their new customers to Rotem as the supplier until a certain number of electricity consumers has been assigned to the supplier under the agreement, subject to the terms and conditions of any agreement. The agreement sets a maximum number of household consumers which can be signed on to the supplier, and a maximum hourly consumption with respect to SMBs. 74 The weighted average remaining contractual period of the agreements is approximately six years, subject to early termination provisions and other provisions. Surplus PPAs with IPPs. OPC sells excess electricity to independent power producers from time to time through subsidiaries, under “spot” agreements. On August 18, 2024, an agreement was signed for the purchase and sale of surplus electricity between Rotem and a third party holding an electricity generation license (the “Electricity Producer”); the term of the agreement is five years. As part of the agreement, Rotem agreed to sell to the Electricity Producer and the Electricity Producer undertakes to purchase from Rotem surplus quantities of electricity, during certain demand hour clusters, at a discount set from the general energy demand management rate (DSM Tariff); in relation to surplus electricity in other demand hour clusters. Pursuant to the agreement, the sale of surpluses are to be made in accordance with fixed maximum and minimum quantities. Agreements for the purchase of capacity and capacity certificates available in the secondary market for sale to OPC’s customers. From time to time OPC enters into short-term agreements for the purchase of capacity certificates and RECs from suppliers. In addition, during 2025, OPC engaged - through its virtual supplier - with a third party in an agreement to purchase capacity certificates totaling 50 MW from a photovoltaic power generation facility, which is expected to reach commercial operation by the end of 2027, over the agreement term, which is expected to end on September 30, 2030 (subject to early termination provisions) at a tariff as agreed between the parties. In addition, OPC will be entitled to receive RECs in accordance with its proportionate share of the total number of RECs to which the facility will be entitled. The agreement includes additional terms and mechanisms as is generally accepted in agreements of this type, including a minimum capacity undertaking of the facility, an agreed compensation mechanism for delays, collateral provision undertakings, assignment clauses and others. Material Customers. In Israel, OPC has several customers characterized by high consumption rates in terms of their total production capacity. OPC’s revenues from electricity generation are highly sensitive to the consumption of material customers. Therefore, if there is no demand for electricity by a material customer (such as, due to malfunctions, suspension or other factors) or payment default by such a customer, this could have a materially adverse impact on OPC’s revenues in Israel. For 2025, one of OPC’s private customers in Israel accounted for more than 10% of OPC’s consolidated revenues (which constitutes approximately 13% of OPC’s revenues); this is also true of revenues from the System Operator, whose share exceeds 10% of OPC’s revenues. Each of OPC’s other private customers, other than Noga, does not exceed 10% of OPC’s consolidated revenues from electricity generation. OPC’s PPAs with private customers in Israel (excluding Noga) are generally similar. Characteristics of the PPA with the material Israeli customer - In January 2023, Rotem and the material customer extended their engagement for an additional period that will start at the end of the term of the existing agreement (including an option to extend the term in accordance with provisions that were set). As part of revising the engagement, certain provisions of the original PPA between the parties were revised, and the customer is expected to increase the capacity it will acquire under PPA prices, as revised, over the next few years. Other arrangements were also revised, including in connection with the option that a generation facility will be built at the customer’s premises and the sale of electricity from renewable energies. Infinya. Hadera is dependent on Infinya, which is currently the sole consumer of steam and a material consumer of electricity from the Hadera Power Plant. The loss of Infinya as an electricity and steam customer could impact the area of activity in several ways (beyond the loss of income); (1) impairment of the applicability of the cogeneration arrangements to the Hadera Power Plant as a result of the loss of Infinya as a substantial steam consumer, and the applicability of conventional tariff arrangements, which are subordinate to cogeneration tariff arrangements; (2) lower electricity sales to customers from the Hadera Power Plant as a result of limitations on transferring energy to the grid. Providing energy to the grid by the Hadera Power Plant under the permanent license is limited to 120 MW (until removal of a technical limitation, which have not yet been achieved) and in view of the direct transmission to Infinya, the electricity Infinya consumes is not deemed electricity transmitted to the grid for purposes of the limit; (3) the termination of the agreement with Infinya or its early termination may, under certain circumstances, constitute an immediate cause of repayment under Hadera’s project finance agreement. The Sorek 2 Generation Facility. The capacity that will be generated by the Sorek 2 generation facility, subject to the commencement of its commercial operation, shall be sold to the desalination facility and to another customer with a generation facility at its premises in accordance with the PPA with it, and the remaining capacity will be sold in accordance with applicable regulations. Accordingly, Sorek 2 entered into a separate agreement with IDE and Mekorot Water Company Ltd. (“Mekorot”) for the supply of electricity and with IDE for the supply of electricity and steam, over a period from the commercial operation date of Sorek 2 and through the end of the concession period. The tariff paid by IDE for the purchase of energy and steam is determined according to the quantities of energy and steam consumed, plus a fixed component in respect of the size of the connection and additional required regulatory components. The tariff is linked to the USD and to gas prices under the terms stipulated in the agreement. The tariff paid by Mekorot is based on the DSM Tariff with a discount on the generation component and the grid component. 75 The agreements include an undertaking for a defined capacity level and additional conditions pertaining to the supply of electricity and steam, provisions pertaining to gas shortage, the netting method and grounds for early termination of the agreements. United States The CPV Group’s projects mainly sell electricity and capacity into the PJM, NYISO and ISO-NE wholesale markets. CPV Renewables’ operating projects, Keenan, Mountain Wind, Maple Hill, Stagecoach and Backbone have entered into long term PPAs. The CPV Group’s renewable projects under development are expected to sell their energy, capacity and RECs in the wholesale market or directly to consumers through long-term PPAs. Backbone, a solar project with a total capacity of about 179 MWdc, received a connection agreement to the grid from PJM and signed a 10-year PPA agreement for 82% of the energy generated and SRECs. The remaining 18% of the project’s capacity is expected to be used to supply CPV Group’s retail energy customers or sold in the spot market. OPC’s Competition Israel Within Israel, OPC’s major competitors are the IEC and private power generators, such as Dorad Energy Ltd., Dalia Power Energies Ltd. of the Meshek Energy group, Rapac-Generation, Shikun & Binui Energy, APM and the Edeltech Group, who, as a result of government initiatives encouraging investments in the Israeli power generation market, have constructed, and are constructing, power stations with significant capacity. In addition, with respect to Hadera 2, OPC believes that Reindeer is also competing for the quota set by the regulation by virtue of which Hadera 2 is to be constructed. In 2024, the energy effectively generated by OPC Energy’s power plants generated in this segment totaled 4.96 TWh, constituting approximately 6.2% of the total energy generated in Israel, and about 10.4% of the energy generated by independent power producers in Israel during that year (including renewable energies). In February 2021, the EA established a regulatory scheme for suppliers with no means of generation for the first time (“Virtual Supply”), including criteria and tariffs to purchase energy for their consumers at the tariffs to be based on an SMP-based component and components affected, inter alia, by the scope of consumption during peak demand. In June 2024, the EA expanded the market to include household consumers having only a basic meter, who could engage with a virtual supplier starting from September 2024, and with conventional suppliers – starting from January 2025. This led to the entry of new players who were not yet active in the Israeli electricity market, and who have received a supply license. Electricity generation using renewable energies Due to gradual adoption of ESG standards and commercial considerations, there is a gradually growing increase in demand for electricity from renewable sources in addition to power from uninterrupted and reliable sources such as natural gas. In recent years, there has been an uptick in the entrance of electricity producers and generation facilities which use renewable energies into the electricity generation market, including PV (photovoltaic) energy, wind energy, and storage-incorporated facilities. Following regulatory developments in Israel, a greater number of high voltage renewable energies producers were able to enter the market, inter alia through virtual suppliers, to end customers. The Israeli renewable energy market comprises many competitors, with varying volumes of activity. OPC’s key competitors in the field of power generation using renewable energies in Israel are Doral Energy Group Ltd, Enlight Renewable Energy Ltd., Meshek Energy Ltd., Shikun & Binui Energy Ltd., and EDF Renewables Israel Ltd. 76 Competition at the supply level As part of implementation of the reform in the electricity sector in Israel, in recent years the EA has taken action to advance the competition in the supply market by means of entry and integration of private suppliers and acceleration of the transition of consumers to receipt of services from those suppliers. Based on the Report of the Israeli Economic Sector for 2025, the market share of the private suppliers reached about 35% of the economy’s entire consumption, where most of the arrangements are mainly with customers having significant electricity consumption (mostly industrial and commercial consumers with high and medium voltage connections). Regarding consumers with low voltage connections, including, among others, most of the household consumers, as at June 2025, only 9% are serviced by private suppliers. In order to increase the ability to transfer household consumers to private electricity suppliers, starting from January 2024 household consumers that do not have a “smart” meter are permitted to contract with a private supplier. Currently, OPC supplies private electricity consumers (indirectly through PPA agreements with two marketers), while in OPC’s estimation, up to the end of 2026 the scope of the sales to household consumers through such marketers is expected to continue to rise. During 2025, at the supply level, the process of change in consumption patterns continued, including for households, which comprises the sale of electricity to numerous end customers and provision of adequate services and ongoing management of customer accounts. Regarding small customers (households and small businesses), players in this channel include mainly communications companies, utility companies, and other entities with experience and relative advantages in distribution to end customers. In addition, as part of the continuing optimization and diversity of the mix of OPC’s customers in Israel, including in view of the future projects being developed by OPC, during 2025, OPC contracted with a number of servers’ farms, including examination of significant expansion of the arrangements with these consumers and/or with additional servers’ farms. In addition to OPC’s activity in this area, there are additional examples of arrangements between players operating in the production channel and actors operating in the retail channel: Cellcom Israel Ltd., Meshek Energy - Renewable Energies Ltd., Bezeq - Israel Telecommunications Corp. Ltd., and Generation Capital Ltd. and others. OPC believes that measures taken by the EA to open the supply segment to competition and to expand the supply options available to suppliers have increased the number of participants operating in the supply segment, such that additional players will be incorporated into the segment (including players currently active in electricity generation segment and do not sell electricity to end users); this is expected to intensify the growing competition in this segment. The new regulation that came into force during 2024 allows all customers in Israel to contract with independent power suppliers - a measure that OPC believes will expand the scope of consumption associated with independent suppliers. OPC Israel’s competitive position is subject to positive and negative factors. OPC believes that the positive factors include: (a) OPC is the first major independent power producer in Israel and has gained extensive knowledge, commercial and operational experience and experience in development; (b) experience in raising adequate capital and financing; (c) OPC’s diverse mix of customers and generation facilities, which diversifies the risk associated with OPC’s activities; (d) OPC’s ownership structure in this area of activity, which enables OPC companies in Israel, among other things, to enter into various intra-group agreements in its area of activity, subject to applicable regulatory provisions. Thus, a mutual platform is created which generates synergy between the activities of OPC’s power plants; (e) most of the private customers with whom OPC entered into PPAs have a consumption profile which optimizes OPC’s revenues from sale of electricity in Israel. OPC believes that the negative factors impacting OPC’s competitive status in this area are as follows: (a) significant exposure to the generation component, both in terms of revenues and expenses; (b) due to the market concentration rules applicable to OPC, there may be restrictions on receiving additional generation licenses; (c) Rotem’s activities are subject to specific regulation, although this factor has somewhat balanced out following the resolution regarding complementary arrangements; (d) exposure to material customers; (e) OPC’s main active projects in this area of activity are gas-fired and have no new active capacity for the sale of electricity generated using renewable energies (which is under development). OPC has several diverse and stable generation sources and customers and works to expand its operation channels in the generation segment and supply segment, including through renewable sources. 77 United States CPV operates in a highly competitive market. Natural gas, solar, and wind projects account for over 87% of new capacity under construction in the U.S. with significant competition among independent power producers and renewable project developers. Independent power producers compete with CPV in selling electricity and capacity to the wholesale electrical grid. In addition, the competitors can also sell electricity to third-party customers by entering into PPAs. Although CPV’s Energy Transition power plants are considered more efficient compared to the market average, and hence they may have lower costs compared to other conventional gas-fired power plants, competition posed by other production sources, and the use of other technologies may have an adverse effect on electricity prices and capacity, and as a result have a negative effect on CPV Group’s revenues. CPV believes that CPV Group project’s share of the total capacity in their respective markets are not significant and allows for significant growth. In addition, CPV’s other competitors in the U.S. energy market include generators of different technology types, such as coal, oil, hydroelectric, nuclear, wind, solar and other types of renewable energies. Some of the generators in different markets are owned and operated by traditional rate-regulated electricity companies, venture capital funds, banks and other financial entities. The large energy demand of hyperscalers, data centers, technology corporations may affect also the structure of the competition and market conditions for generation investment in the industry as some of them seek to purchase power through long-term power-purchase agreements to meet their energy and sustainability goals. The main competitors in the field of energy supply are local electric utility companies, independent power producers, and other suppliers that produce decentralized electricity off the grid and there may be a difference in terms of capabilities, energy sources, and nature of activity, depending, inter alia, on the relevant electricity market. Companies that compete with CPV Group in the field of energy supply are mainly independent power companies engaged in the generation of energy, and other suppliers engaged in supply of energy. CPV invests in developing new projects using a range of technologies in a range of markets while using various types of contracts in order to improve its ability to compete with existing producers and other competitors, and in order to diversify the risks. In addition, CPV believes that it has internal organizational capabilities in all key areas of external and government relations, commodities marketing and trade, finance, licensing, and operations that allow its strategy to develop rapidly and efficiently. OPC’s Seasonality Israel Revenues from the sale of electricity are seasonal and impacted by the “Time of Use” (or “TAOZ”) tariffs published by the EA. As updated by the EA’s decision, the seasons are divided into three in accordance with the resolution of the EA to update the demand hours clusters, as follows: (i) summer—June to September; (ii) winter—December, January and February; and (iii) transition season—March to May and October to November. OPC’s revenues from customers are based on customers’ seasonal consumption, demand hours clusters and tariffs applicable to consumption times. The gas price linkage pursuant to the gas agreements is based on the weighted annual generation component (subject to the Minimum Price). The following table provides a schedule of the weighted EA’s generation component rates for the following periods based on seasons and demand hours, published by the EA: Weighted production rate (AGOROT per kWh) Season Demand Hours January 2025 January 2026 Winter Off-peak 18.36 17.49 On-peak 68.86 69.84 Spring or Fall Off-peak 17.61 16.79 On-peak 21.05 19.95 Summer Off-peak 21.54 20.54 On-peak 110.64 113.76 Weighted Generation Component 29.39 28.9 78 In general, tariffs in the summer and winter are higher than during transitional seasons. The cost of acquiring gas, which is the primary cost of OPC, is not influenced by the tariff seasonality. The following is the average quarterly and annual generation component in 2025 and 2026: Quarter Generation Component for 2025 (agorot per KW) Generation Component for 2026 (agorot per KW) 1 25.17 24.57 2 24.12 23.92 3 36.79 36.50 4 21.70 21.01 Annual 26.96 26.52 For further information on the seasonality of tariffs in Israel, see “—Industry Overview— Electricity generation and supply in Israel.” The following table provides a summary of OPC’s revenues* from the sale of electricity, by season for 2024 and 2025. These figures have not been audited or reviewed. 2024 ($millions) 2025 ($millions) Summer (4 months) 983 939 Winter (3 months) 545 560 Spring and fall (5 months) 704 765 Total for the year 2,232 2,264 * Includes revenues attributed to capacity from Zomet. United States The revenues from generation of electricity are seasonal and are impacted by weather. In general, in natural gas-fueled power plants, profitability is higher during the highest and lowest temperatures of the year, which often coincides with summer and winter. In view of the effects of seasonality, generally, the preference is to conduct maintenance works in power plants, to the extent possible, during the autumn and spring, in which demand for electricity is assumed to be relatively low. The profitability of renewable energy electricity production is subject to production volume and availability, which varies based on wind and solar operations’ patterns as well as electricity price, which tends to be higher in winter unless the project is engaged in advance in a contract for a fixed price. 79 OPC’s Production Capacity and Availability Israel The following table sets forth summary operational information for OPC’s plants in commercial operation in Israel as of and for the years ended December 31, 2025 and 2024: As of and for the Year ended December 31, 2025 As of and for the Year ended December 31, 2024 Entity Power Generation Potential (GWh) (1) Net energy generated (GWh)(2) Actual calculated availability factor (%)(3) Power Generation Potential (GWh) Net energy generated (GWh)(2) Actual calculated availability factor (%)(3) Rotem 3,736 3,073 83.7 % 3,736 3,332 95.1 % Hadera 1,019 970 96.1 % 1,048 943 92.6 % Zomet(4) 3,171 291 67.1 % 3,268 428 83.6 % Gat 620 503 91.6 % 616 397 64.4 % OPC Total 4,837 5,100 (1) The production potential is the net production capacity adjusted for temperature and humidity. (2) The net generation is the gross production capacity during the year, less energy consumed by the power plant for its own use. (3) The availability factor is the period during which the power plant was available for electricity generation, including scheduled and non-scheduled maintenance work. (4) Zomet is a peaker plant. The generation potential does not include the temporary generation limit, which applied during 2025 to each of the generation unit. Scheduled and non-scheduled maintenance work is carried out from time to time in OPC’s power plants (including during 2025), which may affect their generation capacity and availability, and accordingly their operating results. Furthermore, the operation of dual fueled power plants using diesel fuel as a back-up when needed may affect their generation capacity and availability. Rotem Under the New Rotem maintenance agreement, the schedule for the execution of planned maintenance work at the power plant was revised to every 25,000 working hours (estimated at approximately three years). Rotem was shut down in the fourth quarter of 2025 for upgrading and scheduled maintenance which lasted about two months, which had an adverse effect on its results for 2025 compared to 2024. Despite the maintenance work, sales of electricity to customers continued as Rotem purchased electricity from the System Operator in order to meet the full demand of its customers during the shutdown. During 2026, a few days of scheduled maintenance work is expected, which will be integrated into INGL’s scheduled maintenance work. The Rotem Power Plant is operated by natural gas as its primary fuel, with diesel fuel serving as backup (Rotem is therefore obligated to keep a stock of diesel fuel for 200 hours of operation). In the event that the Rotem Power Plant is powered by diesel fuel, its production capacity will be limited to approximately 85%, compared with the power plant’s production capacity using natural gas. Operation of the Rotem Power Plant by diesel fuel is executed based on the requirements of the System Operator, due to shortages of natural gas and inspections when transitioning from operation using gas to operation using diesel fuel. In such case, Rotem is expected to be entitled to a refund in respect of the difference between the cost of energy generation using diesel fuel and Rotem’s generation cost using gas for the energy generated. 80 Hadera In 2025, scheduled maintenance work was conducted for one week, during which the entire power plant was shut down; it was initiated by INGL. In 2026, a planned shutdown of part of the power plant is expected for the purpose of upgrading and maintenance work, expected to last about one month, which will be part of INGL’s annual maintenance work. The timetables for execution of scheduled maintenance work in the power plant could change as a result of various factors, including, among others, the scope of operation of the power plant, security developments in Israel, infrastructure constraints or rescheduled works with the maintenance contractor. During the maintenance work, part of the power plant’s activity is suspended, which adversely affects the operating results of OPC. In addition, OPC is working to repair a technical fault detected at the power plant; currently and until the completion of the repair work, electricity generation at the power plant continues at most of its generation capacity. OPC is working to repair the technical fault in the forthcoming months; this is not expected to have a material effect on Hadera’s results over time given the insurance coverage under the power plant’s insurance policy. The Hadera Power Plant is a dual fuel plant operating using natural gas as its primary fuel, and it must keep a stock of diesel fuel for backup purposes in an amount sufficient for 100 hours of operation at full load. Zomet Zomet’s installed generation capacity according to its permanent production license is approx. 396 MW. Furthermore, under the terms of the permanent license, Zomet is required to meet a minimum operational capacity level of 88% in the first year of operation and 92% thereafter. In order, to mitigate the risk of operational failure due to a detected technical fault, and in coordination with the contractor, under the process of investigating and repairing the fault, the power plant’s capacity has been partially limited since; in addition, maintenance work was carried out alongside the gradual replacement of the generation units. These factors have an adverse effect impact on the power plant’s availability and accordingly impacted its financial results during 2025. The process of repairing the fault, including completing the replacement of the production units, has begun, and OPC believes it is will be mostly completed by the end of 2026, with the partial capacity as stated, which OPC estimates is expected to reach 65%-70% of the power plant’s capacity (similarly to its capacity in 2025) - which is expected to adversely affect the power plant’s results. Gat During 2025, unscheduled maintenance work was conducted in Gat over two weeks in November 2025, due to a malfunction following which the power plant’s activity was suspended. In 2026, a planned shutdown of the power plant is expected for the purpose of executing upgrading and maintenance work in the gas turbines, which is expected to last approximately one month. The Gat Power Plant is powered solely by natural gas. During 2025, the power plants operated using diesel fuel at Noga's request on days in which, as part of the War, the gas rigs were shut down, thereby meeting the needs of the electricity sector. Throughout the maintenance work, electricity sales to OPC’s customers continue in the Rotem, Hadera and Gat power plants, including through the purchase of electricity from the System Operator, in order to fully respond to the demand during the shutdowns. 81 United States The table below sets forth an overview of the generation capacity of CPV’s plants in commercial operation for 2025 and 2024. 2025 2024 Net Electricity generation (GWh)(1) Actual Generation(2) (%) Actual Availability Percentage (%) Net Electricity generation (GWh)(1) Actual Generation (%)(2) Actual Availability Percentage (%) Energy Transition Projects Shore 3,828 60.6 % 87.7 % 3,612 56.9 % 92.4 % Maryland 4,718 73.3 % 95.9 % 3,628 56.3 % 90.3 % Valley(1) 4,725 77.7 % 83.5 % 5,002 82.1 % 89.1 % Fairview(2) 7,513 81.5 % 87.1 % 7,610 82.1 % 88.5 % Towantic(3) 4,812 67.1 % 78.5 % 5,593 77.7 % 89.9 % Three Rivers 6,456 60.1 % 85.2 % 6,366 59.9 % 76.9 % (1) A decrease in the power plant’s capacity stemming mainly from performance of planned maintenance work in the fourth quarter of 2025. (2) In December 2025, as part of planned maintenance work, a malfunction occurred in one of the generation units, as a result of which the power plant’s generation capacity was temporarily limited to about 50% of its full capacity. CPV Group estimates that the power plant is expected to return to full operation in 2027. Fairview has submitted a claim under the power plant’s insurance policy, both in respect of the direct costs to repair the damage and for loss of the expected profits. (3) In the second quarter of 2025, planned maintenance was performed at the power plant, as part of which a significant item of equipment was replaced. This item is insured under the insurance policy covering the power plant, and a cash compensation was received that covers most of the costs required for its replacement and installation. 2025 2024 Net Electricity generation (GWh)(1) Actual Generation(2) (%) Actual Availability Percentage (%) Net Electricity generation (GWh)(1) Actual Generation (%)(2) Actual Availability Percentage (%) Renewable Energy Projects Keenan 247 18.5 % 95.8 % 261 19.5 % 95.8 % Mountain Wind 212 29.7 % 97.1 % 197 27.5 % 91.7 % Maple Hill 157 18.0 % 97.4 % 164 18.7 % 93.4 % Stagecoach(3) 171 24.4 % 90.2 % 136 25.7 % 98.1 % (1) The net electricity generation is the gross generation during the period less the electricity consumed for the self-use of the power plants. (2) The actual generation percentage is the electricity produced by the power plants relative to the maximum amount of generation capacity during the period and is affected by ordinary course maintenance activities at the power plants, which are scheduled at fixed intervals. Such maintenance activities typically last for approximately 30–50 days and reduce the power plants’ generation and availability until such maintenance has been completed. The actual capacity rate (availability percentage), was reduced for Shore and Fairview due to unplanned outage events, and for Valley, due to an extended planned outage. Towantic’s decrease in 2025 compared with 2024 was mainly due to a planned major maintenance outage that was performed at the power plant in 2025. As part of that maintenance, a significant item of equipment was replaced, that did not materially impact the actual capacity rate. CPV Group’s projects may be under planned and unplanned maintenance (or experience production limitations or technical failures) from time to time, including as occurred in 2025. In this context, following 2025 autumn maintenance works in Fairview a malfunction occurred which caused an extended outage of the plant following which Fairview resumed partial operation of one unit out of two and is currently expected to complete remediation works and resume to full operation in Q1 of 2027. The event and the impacted equipment are covered under the insurance policy for the Fairview power plant. CPV expects that it will receive monetary indemnification to cover most of the costs to repair or replace the equipment and business interruption. In 2026, in addition to immaterial planned maintenance outages, a major planned maintenance outage is expected for Shore and Maryland. (3) The Stagecoach project commenced commercial operations in April 2024. The Stagecoach project entered into a PPA with a utility company for the supply of all the electricity to be produced for a period of up to 30 years from the project’s commercial operation date, at market prices, for the sale to a global company of 100% of the project’s SRECs, as well as a hedge covering the entire electricity price of the quantity that is produced and sold to the utility company, at a fixed price, for a period of 20 years from the date of commercial operation of the project. 82 The potential generation is the gross generation capability during the period after planned maintenance and less the electricity used for the power plant’s internal purposes. The net electricity generation is the gross generation during the period less the electricity consumed for the self-use of the power plants. The actual generation percentage is the net electricity produced by the power plants relative to the maximum generation capacity during the period; it is affected by unplanned outages or maintenance in the power plants, which are conducted in regular time intervals. Major planned maintenance normally takes 30 to 50 days and reduces the power plants’ scope of production and capacity until maintenance is completed. The actual capacity rate (availability percentage) in 2025 was reduced for Shore and Fairview due to unplanned outage events, and for Valley due to an extended planned outage. Towantic’s decrease in 2025 compared with 2024 was mainly due to a planned major maintenance that was performed at the power plant in 2025. As part of that maintenance a signification item of equipment was replaced, which did not materially impact the actual capacity rate. It is emphasized that CPV Group’s projects may be under planned and unplanned maintenance (or experience production limitations or technical failures) from time to time, including as occurred in 2025. Following 2025 autumn maintenance works in Fairview, a malfunction occurred which caused an extended outage of the plant following which Fairview resumed partial operation of one unit out of two and is currently expected, based on CPV Group’s current assumption of available information, to complete remediation works and resume full operation during 2027. In 2026, in addition to immaterial planned maintenances, there is an expected major planned maintenance for Shore and Maryland. Forward Capacity Obligations ISOs’ and RTO’s capacity markets (including PJM) include “bonuses” and “penalties” imposed on generators based on operating performance of the facilities during pre-defined emergency events. If a facility is unavailable during the emergency event (which includes extreme weather events), penalties for non-availability could have a material negative financial impact to the project (and are not insured). OPC’s Property, Plants and Equipment Israel For summary operational information for OPC’s operating plants in Israel as of and for the year ended December 31, 2025, see “—Our Businesses—OPC’s Business—OPC’s Description of Operations—Israel.” OPC leases its principal executive offices in Israel. OPC owns all of its power generation facilities. As of December 31, 2025, the consolidated net book value of OPC’s property, plant and equipment was $1,370 million. The table below sets forth a summary of primary land plots owned or leased by OPC, or that OPC has right of use in, in which OPC operates (1 dunam = 1,000m2). 83 Site Location Right in Asset Area and Characteristics Real estate held through Rotem Land on which the Rotem Power Plant was built Mishor Rotem Lease About 55 dunams(1) Real estate held through Hadera Hadera Energy Center and the Hadera power plant (including emergency road)(2) Hadera Lease(3) About 30 dunams (Power Plant and Hadera Energy Center) Land held by Zomet (through Zomet HLH General Partner Ltd. and Zomet Netiv Limited Partnership) Land on which the Zomet power plant was built Plugot Intersection Zomet Netiv Limited Partnership—(by force of a development agreement with ILA)—Lease About 85 dunams Land held through Gat Land on which the Gat Power Plant was built Gat Ownership About 12.4 dunams Right-of-use of the land for Sorek 2 Land on which the Sorek 2 generation facility is being constructed Sorek 2 Desalination Facility Right of use(4) About 2 dunams Real estate (including options for land) held by Hadera for Hadera 2 Hadera 2—Land near the area of the Hadera Power Plant Hadera Annual option to extend the lease through the end of 2027. In December 2024, the option for 2025 was exercised About 68 dunams Land Agreement of Ramat Bekka Ramat Bekka Neot Hovav Development authorization About 2,270 dunams (the first tender) + about 1,670 dunams (the second tender) Real estate (including options for land) held by Brosh corporations Brosh corporations Brosh B1 Partnership A 9-year option as from September 9, 2025 Approximately 93 dunams Land Agreement of Rotem 2 Land near to space on which Rotem Power Plant was built Mishor Rotem Lease About 55 dunams (1) Rotem is not entitled to reassign its rights under the lease agreement, including to lease, rent or transfer possession of the lot for a period exceeding that stated in the lease agreement, and is not entitled to pledge the lot or any other rights under the lease agreement, without the lessor’s advance written consent. (2) The Energy Center - Agreement to lease an area of 3,490 sq.m within the Infinya plant for 20 years from the power plant’s commercial operation date. Infinya may inform Hadera that it is interested in dismantling, scrapping or selling the Energy Center’s equipment. One of the boilers was removed from the site, and the Energy Center serves as backup for the supply of steam from the Hadera Power Plant. (3) OPC is negotiating an agreement to acquire interests in the land of the project and of the Hadera Power Plant from Infinya (instead of the lease agreement and the rental option agreement), with the consideration expected to total approximately NIS 450 million. (4) The land on which the Sorek 2 generation facility is located is owned by the Israeli Development Authority and the State of Israel. As part of the tender documents of the State of Israel for the construction, operation, maintenance and transfer of the Sorek desalination facility, the right-of-use was obtained for the land of IDE (the concessionaire of the desalination facility) for the purpose of constructing such desalination facility and Sorek, in its capacity as the IPP contractor in the project, for the purpose of building and operating the project in the land area, for the duration of the concession period, where the Sorek B IPP Agreement with IDE confers upon Sorek 2 the same rights which IDE has with the State with respect to the land. Such land is located in Rishon LeZion. OPC believes that prior to the publication of the tender documents, the State arranged with the ILA to allocate and lease the land for the construction of the desalination facility on the land area, for an allocation period of 49 years from the approval date by the ILA (May 2015) until May 2064. 84 United States In general, the land on which the projects are situated (both the operational projects and the projects under construction) is held in a number of ways—ownership, lease with use right, under a permit and licenses. In some cases, the facilities themselves are located on owned land, where there are easements in land surrounding the facility for purposes of interconnection and transmission. In addition to the project lands, CPV leases office space for use by the headquarters in Silver Spring, Maryland, Sugar Land, Texas, and in Braintree, Massachusetts pursuant to multi-year lease agreements. Set forth below is information on the lands on which CPV plants in commercial operation (and Backbone, which is under construction) are located. Site Location The right in the property Area and characteristics Expiration date of right Conventional Energy Projects Shore Middlesex County, New Jersey Ownership About 111,290 square meters (28 acres) N/A Maryland Charles County, Maryland Ownership / easements / licenses and permits / authority About 308,290 square meters (76 acres) N/A Valley Wawayanda, Orange County, New York Substantive Ownership(1) / easements or permits About 121,406 square meters (30 acres) N/A Towantic New Haven County, Connecticut Ownership / easements About 107,242 square meters (26 acres) N/A Fairview Cambria County, Jackson Township, Pennsylvania Ownership / easements About 352,077 square meters (87 acres) N/A Three Rivers Grundy County, Illinois Ownership / easements About 445,154 square meters (110 acres) N/A 85 Renewable Energy Projects Keenan Woodward County, Oklahoma Contractual easements Rights to land and the equipment December 31, 2040 Mountain Wind Aggregated for the four wind farms of Mountain Wind Franklin, Oxford and Waldo Counties, Maine Contractual easements and leases Approximately 15,000,000 square meters (3,700 acres) Forty years (Thirty years for 20% of Spruce Mountain) Various 2046—2055 Maple Hill Cambria County, Jackson Township, Pennsylvania Ownership / easements About 3,063,470 square meters (757 acres, of which 11 acres are leased) With regard to the leased area December 1, 2058 Stagecoach Macon County, Georgia Lease Agreement Approximately 2,541,426 m² (628 acres) May 22, 2042 with option to extend for an additional 20 years Backbone Garrett County, Maryland Lease agreement Approximately 5,463,256 m² (1,350 acres) Commencement of the operating period, plus an option to extend by five consecutive periods of seven years during operations. Rogue’s Wind Cambria County and Clearfield County, Pennsylvania Easements Approximately 26,304,566 m² (6,500 acres) July 2, 2057 with option to extend term with two ten-year renewal options. Low Carbon Projects Basin Ranch Ward County, Texas Ownership 1,323,500 m² (327 acres) N/A (1) This land is held for the benefit of Valley, which is entitled to transfer it to its name. The intangible assets of CPV Group primarily include lease agreements for projects and power purchase agreements. 86 OPC’s Raw Materials and Suppliers Israel Gas Supply Agreements Natural gas serves as the primary raw material for electricity generation in this area of activity. OPC’s active power plants acquire gas primarily from the Karish Tanin Reservoir, which is held by Energean, and from the Tamar Group. Agreements with the Tamar Group The power plants owned by OPC in Israel use natural gas as their primary fuel, with diesel fuel and fuel oil as backup. Rotem Rotem purchases natural gas from the Tamar Group, pursuant to a natural gas supply agreement that will end at the earlier of 16 years from the commencement of gas supply (April 2013) or the consumption of the total contractual quantity as defined in the agreement (subject to the parties’ option to extend the agreement by two years under the conditions set). The total contractual quantity under the agreement amounts to 10.6 BCM. the Tamar Group estimated the value of the agreement to be approximately $2.5 billion (excluding reductions in quantities and the subsequent amendments). Certain annual quantities in the agreement between the Tamar Group and Rotem are subject to a Take or Pay (ToP) obligation, based on a mechanism set out in the agreement. Under certain circumstances if payment is made for a quantity of natural gas that is not actually consumed or a quantity of gas above the ToP amount is purchased, Rotem may, subject to the restrictions and conditions, accumulate this quantity, for a limited time, and use it in accordance with the terms of the agreement. The agreement includes provisions of assignment of rights to related parties for quantities that were not consumed under certain conditions and up to close to their expiration date. Rotem may sell surplus gas under a secondary sale, subject to conditions set in the agreement. In addition, Rotem was awarded an option that was exercisable in 2020-2022, to reduce the daily contractual quantity to a certain rate set out in the agreement. Pursuant to the agreement, the price of gas is based on a base price in NIS, which was set on the date of signing the agreement, linked to changes in the generation component tariff, which is part of the DSM Tariff, and in part (30%) to the USD representative exchange rate. The natural gas price formula set in the agreement between the Tamar Group and Rotem is subject to a minimum price in USD. Hadera In September 2016, Hadera entered into another gas supply agreement with the Tamar Group. The gas supply agreement will expire at the earlier of fifteen years after the commencement of supply from the Tamar Reservoir (April 2013), or at the end of the consumption of the total contractual quantity. Furthermore, if a quantity of gas at the rate set out of the total contractual quantity is not consumed, both parties have the right to extend the agreement by the earlier of consumption of the full contractual quantity or two additional years. The price of gas is denominated in USD, is linked to the weighted average of the generation component published by the EA and includes a minimum price. It is estimated that the total amount of the agreement may amount to approximately $0.7 billion (assuming that the overall quantity will be consumed). According to the agreement, the Tamar Group has an obligation to supply all of the quantities included in the agreement. Hadera has a ToP commitment regarding a certain annual quantity of natural gas. Hadera has an option to reduce part of the daily contractual quantity to a certain rate as set out in the agreement. In February 2020, in accordance with the amendment signed between the parties, Hadera gave notice of the date from which the average quantity will be calculated for purposes of calculating the reduced quantities, subject to adjustments as described above. Upon the commercial operation of the Karish Tanin Reservoir in 2023 and the acquisition of natural gas in accordance with the agreement with Energean, the quantity and purchase cost of natural gas from the Tamar Group was reduced. In addition, in September 2016, Hadera and the Tamar Group engaged in an additional agreement for the sale and purchase of gas. The additional agreement expires upon the earlier of fifteen years from January 2019 or the date on which the total contractual quantity is consumed. The gas price is denominated in USD and is linked to the weighted average of the generation component published by the EA and includes a minimum price. Supply of the gas in accordance with the additional agreement, is on an interruptible basis. Hadera has an early termination right in respect of the additional gas agreement in certain circumstances. Accordingly, in June 2022, Hadera informed The Tamar Group of such early termination, and accordingly the additional agreement was terminated on June 30, 2023. 87 Gas supply agreement assigned to Hadera by Infinya. In 2012, Infinya entered into an agreement with the Tamar Group for the supply of natural gas, which has been assigned to Hadera. This gas supply agreement expires upon the earlier of April 2028 or the date on which Hadera consumes the entire contractual capacity. Both contracting parties have the option to extend the agreement, under certain conditions. The price of gas is linked to the weighted average of the generation component tariff published by the EA, and it is also subject to a price floor. According to the agreement, the gas shall be supplied on a firm basis, and includes a take or pay obligation, by Hadera. According to the agreement, Hadera has the option to effectively reduce the purchased gas quantities by approximately 50%, subject to certain conditions. In June 2022, Hadera exercised the option to reduce the quantities as stated above, which came into effect in March 2023. Gat Gat purchases natural gas from the Tamar Group pursuant to a gas supply agreement which includes conditions for the purchase of a minimum quantity of gas and other arrangements. In 2016, the parties signed an addendum to the supply agreement, whereby the term of the agreement was extended to 18 years from the first supply date (with an option to extend by further two years, subject to the terms set out in the addendum). In March 2020, the supply agreement became a continuous agreement, as part of which the Tamar Group undertakes to sell to the Gat Partnership the required quantity, and the Gat Partnership undertakes to purchase a minimum annual quantity (which was reduced in 2021 under the terms and conditions of the agreement), or alternatively - to pay for the quantity it has undertaken to purchase even if it had not actually purchased it (take or pay). The Gat Partnership started purchasing gas needed for the Gat Power Plant from the gas reservoirs and in the secondary market under “spot” agreements. The agreement included additional provisions and arrangements customary in agreements for the purchase of natural gas, including with regard to maintenance, gas quality, force majeure, limitation of liability, early termination provisions under certain cases subject to conditions, assignments and a dispute resolution mechanism. In accordance with the arrangement, the Tamar Group may demand - taking into account certain financial data or rating - guarantees according to the value of the number of gas consumption days, in accordance with the contractual quantity set forth in the agreement. Furthermore, the agreements include provisions regarding restrictions on secondary gas sale by the partnership to third parties, all in accordance with set provisions and arrangements. Maintenance work and Shutdowns (Tamar). In 2025, the Tamar reservoir operated regularly except for non-scheduled and scheduled shutdowns (for a short period during Operation Rising Lion), for which netting was carried out between the parties. OPC expects that a number of maintenance works is expected to take place in the Tamar Reservoir in 2026 as well. In addition, during Operation Lion’s Roar, all gas rigs were shut down for varying periods of time; the Tamar reservoir resumed operations after several days of shutdown. Agreements with Energean In December 2017, Rotem and Hadera signed agreements for the purchase of natural gas with Energean Israel Ltd. (“Energean”), which has holdings in the Karish Reservoir. According to the agreements, the total initial base natural gas quantities to purchase by Rotem and Hadera was approximately 5.3 BCM and approximately 3.7 BCM, respectively (the “Total Contractual Quantity”). The agreement includes a ToP mechanism, whereby Rotem and Hadera undertake to pay for a minimum quantity of natural gas even if they have not used it. The agreements include additional provisions and arrangements customary in agreements for the purchase of natural gas, including with regard to maintenance, gas quality, limitation of liability, buyer and seller collateral, assignments and liens, dispute resolution and operating mechanisms. In accordance with the regulation, OPC is required to provide guarantees under certain conditions set forth in the agreement, including a downgrading of the rating, according to the value of the number of gas consumption days, in accordance with the contractual quantity set forth in the agreement. As part of an amendment to Rotem and Hadera’s Energean agreements of 2019, the rate of gas consumption by Rotem was accelerated, such that Rotem’s daily and annual contractual gas consumption from Energean was increased by 50%, with no change in the Total Contractual Quantity being purchased from Energean. Accordingly, the agreement period was updated to the earlier of 10 years or until the Total Contractual Quantity has been consumed (instead of the earlier of 15 years or until the Total Contractual Quantity will have been consumed) (the “Additional Agreement Term”). The agreements with Energean include circumstances under which each party to the agreements will be entitled to terminate the relevant agreement before the end of the first agreement period (or the Additional Agreement Term), including cases of prolonged supply interruptions, compromised collateral, among others. The price of the natural gas in the agreements with Energean is denominated in USD and is based on an agreed formula, which is linked to the generation component and includes a minimum price. The original total financial amount of the agreements was estimated at approximately $1.3 billion (assuming consumption of the total basic quantity and in accordance with the original agreements and in accordance with the gas price formula as of the engagement date) and depends mainly on the generation component, the increase of the quantities as described below and the volume of gas consumed. In August 2022, Rotem and Hadera served Energean with a notice regarding an increase in the contractual gas quantity under the terms of the original Energean agreements and in November 2022, Rotem served Energean with a notice of the exercise of the option to acquire an additional immaterial quantity, as set out in the amendment to the agreement with Energean. At the beginning of 2023, Energean issued a notice to Hadera and Rotem regarding the completion of the commissioning and commercial operation on March 26, 2023. In addition, in 2023 Rotem and Hadera recognized a contractual amount totaling approximately NIS 18 million (approximately $5 million), which was received during 2025 and recognized in the cost of sales line item. 88 Maintenance work and Shutdowns. During 2025 there were several scheduled maintenance days in the Karish reservoir, and the periods in which the reservoir was shut down or operated on a partially on a non-scheduled basis, due to, among other things, Operation Rising Lion, for which netting was carried out between the parties. OPC expects in 2026 a maintenance for the period of a few weeks in the Karish Tanin Reservoir. In addition, during Operation Lion’s Roar, all gas rigs (including the Karish reservoir) were shut down for varying periods of time; and while the Tamar reservoir resumed operations after several days of shutdown, the Karish and Leviathan reservoirs have not yet resumed operations. Natural gas purchase agreement – Leviathan Under Sorek B IPP Agreement with IDE, a mechanism was set for the supply of natural gas to Sorek 2 by virtue of the gas agreements signed between IDE and holders of interests in the Leviathan natural gas field (the “Leviathan Gas Agreement”), for a period of 24 years and 11 months starting from the commercial operation of the desalination facility. Under the agreement, Sorek 2 assumed IDE’s rights and obligations under the Leviathan Gas Agreement on a back-to-back basis, except with respect to excluded arrangements. It was also determined that IDE reserves certain independent rights, provided that these conditions will not materially adversely affect OPC and while making adjustments to the arrangements between the parties. Reporting, billing, payment and dispute resolution mechanisms were further provided for, as was OPC’s right to reject off-specification gas. The gas price under the Leviathan Gas Agreement is denominated in USD for the entire term of the agreement and includes price adjustment mechanisms that may be activated in the event of a breach of the commercial balance. The agreement includes a ToP mechanism pursuant to which Sorek 2 is required to pay for a minimum quantity of natural gas, calculated from the annual contract quantity as defined therein. The agreement also establishes arrangements for reducing this quantity in accordance with the guidance of the Israel Water Authority and its Water Desalination Administration with respect to the operation of the desalination plant at the site. The Leviathan Gas Agreement includes additional provisions and arrangements customary in natural gas purchase agreements, including with regard to maintenance, mechanisms regarding gas quality, limitation of liability, dispute resolution, maintenance and operating mechanisms. Furthermore, the agreements include provisions regarding restrictions on the sale of gas to third parties, who are not related parties and cases which give rise to an early termination right. Sorek 2 has a commitment to IDE with respect to the power plant's gas consumption; this includes, among other things, payments, the acquirer's undertaking under the Leviathan Gas Agreement to consume certain quantities of gas under the terms of the agreement, placing the orders - all in accordance with the terms, prices and limitations set in the Leviathan Gas Agreement, and IDE is entitled to offset these payments from payments due to Sorek 2. The back-to-back mechanism applies, among other things, to gas-supply failures, gas which is off-specification, force majeure events, maintenance work, allocations and supply reductions. Concurrently, it was determined that OPC is not required to provide collateral or guarantees by virtue of the gas agreements, and that IDE reserves independent rights regarding the exercise of rights including its right of early termination of the gas agreement and entering into a new gas agreement, provided that these conditions will not adversely affect Sorek 2 and in the event of price reduction – adjusting the consideration for the electricity. Reporting, billing, payment and dispute resolution mechanisms were also provided for, as was Sorek 2's right to reject off-specification gas supply under the gas agreements. 89 Natural gas purchase agreement – from an entity which is not a gas supplier On March 18, 2024, a partnership wholly-owned by OPC contracted with a third party (who is not a gas supplier) under an agreement for the purchase of natural gas. The agreement will terminate on June 30, 2030 or at the earlier of: the end of the consumption of the total contractual quantity of approximately 0.46 BCM as set out in the agreement. Under the agreement, the seller undertook to provide to OPC (through its partnership) a daily quantity of gas, to be decided by OPC each month, in accordance with the mechanism set out in the agreement, and OPC assumed a take-or-pay liability for a certain annual consumption as set out in the agreement. The agreement includes arrangements regarding quantities consumed above or below the minimum annual quantity. The agreement contains additional provisions and the customary arrangements in agreements for the purchase of natural gas, including regarding natural gas quality and supply, and the gas price is denominated in USD, based on a consensual formula which is linked to the generation component and stipulates a minimum price. In addition, the agreement contains customary provisions relating to undersupply, force majeure, limitation of liability, early termination in specific cases (subject to conditions), and assignment. Engagement with ICL Group Ltd. (ICL) for the procurement of surpluses In May 2025, OPC (subsequent to approval by its audit committee) entered into an agreement with ICL’s subsidiary Dead Sea Works Ltd., to procure power and energy surpluses to Rotem, amounting to a maximum of 40 MW/h, with a discount on the demand side management tariff (DSM Tariff), with Rotem undertaking to consume a certain annual quantity (ToP), divided by seasons and demand hours clusters as agreed between the parties and for a period of five years with the option of terminating the agreement by each party upon 12-month prior notice. The agreement includes customary mechanisms in contractual engagements of this type, including with respect to availability, maximum seasonal capacity and a demand hour cluster and commitment to purchase minimum quantities of electricity in a take or pay format. OPC’s undertakings to purchase energy are in accordance with minimum quantities and prices calculated on an annual basis (a variable undertaking subject to seasonality and demand hours), and with an average discount on the generation component greater than the rate offered to OPC by suppliers as part of a purchase from the System Operator as a virtual supplier with the right for OPC to shift the undertaking under certain conditions between seasons and to the following year. During 2025 (from the date of commencement of the aforementioned contractual engagement until the end of the year), the scope of the agreement amounted to approximately NIS 22 million ($7 million). Zomet. Pursuant to the Zomet Regulation (Regulation 914), Zomet may receive gas required for its operations by either: (1) signing a gas agreement; (2) signing another agreement for supply of natural gas (for example, purchase of gas from another reseller or purchase of gas from other gas consumers) which permits supply of gas to the facility during all hours of the year; (3) if Zomet is unable to supply gas to the power plant during all hours of the year in accordance with alternatives (1) and (2) above, separately or jointly, it will receive gas based on the directives of the System Operator as part of Regulation 914. Currently, OPC meets Zomet’s demand for gas under OPC gas agreements. Gas Transmission Agreements Rotem. Transmission of natural gas from the gas supplier to Rotem is carried out through the INGL natural gas transmission system. Rotem entered into a gas transmission agreement with INGL which term is until July 31, 2029 or until its early termination, including a 5-year extension option, subject to advance notice. For transmission services, INGL charges gas consumers (including Rotem) a tariff which is set by the Natural Gas Authority, and which includes a (fixed) capacity component and a gas transmission component (payable according to the actual gas transmission). Pursuant to the agreement, in the event of capacity shortage in the transmission system, Rotem is entitled to receive the proportionate share of capacity it ordered out of the total capacity ordered by gas consumers. The agreement sets forth a number of cases wherein INGL is entitled to discontinue providing its transmission services, including payment default and breaches not remedied within the period stipulated. Each of INGL and Rotem have termination rights in specified circumstances. Hadera. Infinya entered into an agreement with INGL for the transmission of natural gas to the Hadera Energy Center which was assigned to Hadera under the acquisition of Hadera’s shares in 2015. The terms and conditions of the gas transmission agreement to Hadera are essentially the same as those of Rotem’s gas transmission agreement. In December 2015, the transmission agreement was amended for gas transmission to the Hadera Power Plant to be arranged through a new pressure reduction and measurement station (“PRMS”) located near the plant. The agreement expires on the earlier of: (i) 16 years from the commercial operation date of the PRMS; (ii) expiry of the INGL license (August 1, 2034); and (iii) termination of the agreement in accordance with its terms and conditions. In addition, Hadera has the option to extend the agreement period by an additional 5 years. 90 Zomet. In December 2019, Zomet entered into an agreement with INGL for the transmission of natural gas to the Zomet power plant. The agreement period is 15 years from piping of first gas (which started in December 2022), including a 5-year extension option, subject to advance notice, under terms and conditions that are customary in gas transmission agreements signed by INGL at that time. The agreement is subject to cancellation under certain conditions. OPC provided a corporate guarantee in connection with Zomet’s obligations under the agreement. Gat. In March 2012, the Gat Partnership and INGL signed an agreement for transmission of natural gas to the Gat Partnership’s facilities. The agreement term is 15 years from each facility’s respective gas piping date (June 2014 for the partnership’s facilities and June 2019 for the power plant’s facilities). The agreement includes a 5-year extension option for each of these periods, with prior notice, under the customary terms and conditions for the gas transmission agreements INGL enters into at the time. Sorek 2. The gas transmission to Sorek 2 is carried out by INGL’s transmission system. IDE entered into a transmission agreement with INGL. Accordingly, similarly to the Leviathan Gas Agreement, under Sorek 2’s IPP agreement with IDE, a mechanism was set, according to which the transmission of natural gas to the power plant is carried out by virtue of the transmission agreement between IDE and INGL; Sorek 2’s rights and obligations with respect to the above gas transmission agreement are applied on a back-to-back basis, and IDE is entitled to offset such payments from payments due to Sorek 2. The terms and conditions agreed upon with INGL are similar to OPC's engagements with INGL with respect to OPC's other power plants, as stated above. Other Agreements Construction Agreements Sorek 2 EPC. In June 2021, Sorek 2 entered into a lump-sum turnkey EPC agreement (the “Construction Agreement”) with BHI Co. Ltd. (“BHI”), a South Korean-owned corporation, for the construction of a gas-fired power generation facility with an installed capacity of up to 87 MW. Under the Construction Agreement, BHI will serve as the construction contractor for the Sorek Generation Facility, with all work to be performed in accordance with the milestones, terms, and completion dates specified for each project component. IDE Group Corporation, the construction contractor for the desalination facility, is also a party to the construction agreement in its capacity as an additional work commissioner. Sorek 2’s share in the amount payable to BHI was approximately $42 million, including the amount payable for the purchase of the gas turbines. The Construction Agreement sets forth, among other things, mechanisms for agreed and capped compensation in respect of delays, non-compliance with execution and availability requirements as well as the scope of the contractor’s liability and requirements for provision of guarantees in the different stages of the project. GE Supply Agreement. In addition, in June 2021, Sorek 2 entered into an agreement for the supply of a gas turbine and auxiliary equipment to the energy generation facility with companies in the General Electric Group (“GE”) the “Equipment Supply Agreement”. As part of the Equipment Supply Agreement, GE has undertaken, inter alia, to supply the turbine and its related equipment, to provide support to the construction contractor, as well as commissioning and testing the equipment, all in accordance with terms, milestones and dates agreed between the parties. Pursuant to the agreement between BHI and Sorek 2, once the limited notice to proceed was issued and the first payment to GE was made, the Equipment Supply Agreement was assigned to BHI in the Construction Agreement discussed above. Maintenance Agreement. Sorek 2 and GE entered into a long-term turbine and auxiliary equipment maintenance agreement for a 16-year term with an option to extend to 25 years, as of the commercial operation date of the Sorek Generation Facility. The maintenance agreement contains the standard provisions on equipment performance obligations, capped liquidated damages, compliance with treatment schedules, GE’s warranty for the equipment and services, and guarantees by both parties’ parent companies. 91 In September 2021, a full notice to proceed was issued to the construction contractor. Following the deterioration of the security situation in Israel against the backdrop of the War, BHI received “force majeure” notices, according to which delays are expected in the schedules for the construction of the facility due to the War, as a result of, among other things, difficulties in dispatching foreign teams to the site. Following an escalation of the War and Operation Rising Lion, in 2024 and 2025, notices were received from BHI and GE regarding evacuation of the contractors’ migrant workers from Israel due to the aforementioned security situation. According to the construction contractor and the equipment supplier, the security situation prevalent in Israel constitutes a force majeure, and accordingly - the construction contractor demanded that an increase in costs be recognized. In this context, Sorek 2 has informed IDE and the Israeli government that schedule overruns and delays in the completion of construction by the contractor are expected due to the above, and has submitted a request, in accordance with the project agreements, to recognize higher expenses due to the continued effects of force majeure events on the project. There is no certainty regarding the outcome of Sorek 2’s request. In addition, due to Operation Lion’s Roar, BHI announced that it is evacuating teams from the Sorek 2 site, and, there is no certainty regarding the effects of the notice and other potential schedule overruns. Such schedule overruns involve an increase in the project costs and/or could constitute failure to comply with undertakings to such third parties. The ultimate consequences of these delays (including other potential delays), considering, inter alia, various force majeure claims that have not yet been fully investigated to date, are uncertain. A delay in the commercial operation by Sorek 2 beyond the original contractual date, which is not deemed a justified delay as defined in the project agreements, may trigger the payment of a limited-rate graduated monthly compensation (taking into consideration the duration of the delay, with a delay beyond the utilization of the compensation cap possibly giving rise to a termination right). The construction work, its completion, the commercial operation date, and the construction costs have been adversely affected by the War and/or its implications during 2025 and thereafter. The construction of the Sorek 2 Generation Facility which is under delivery inspections has been substantially completed and its commercial operation is subject to the fulfillment of certain conditions which have not yet been met, primarily those pertaining to the completion of the desalination facility, and operational or technical factors associated with completion of the work at the project site; these have been affected, among other things, by the security situation in Israel and by disruptions during 2025 and thereafter in the arrival of teams and equipment to Israel due to the War and the scaling down of their presence when the War intensified. According to the construction contractor and the equipment supplier, the security situation prevalent in Israel constitutes a force majeure, and accordingly - the construction contractor demanded that an increase in costs be recognized. Sorek 2 has informed IDE and the Israeli Government that scheduled overruns and delays in the completion of construction by the contractor are expected due to the above, and has submitted a request, in accordance with the project agreements, to recognize higher expenses due to the continued effects of force majeure events on the project. Such schedule overruns involve an increase in the project costs (beyond the expected cost noted above) and/or could constitute failure to comply with undertakings to such third parties. Maintenance and Operation Agreements Rotem. In December 2023, Rotem entered into a new maintenance agreement with Mitsubishi Power Europe Ltd. and a company operating on its behalf that served as a local contractor (together “Mitsubishi”) for a total estimated cost of approximately EUR 67 million to be paid over the term of the agreement, in accordance with a payment schedule set forth in the agreement (the “New Rotem Maintenance Agreement”). The New Rotem Maintenance Agreement replaced Rotem’s existing maintenance agreement with Mitsubishi Heavy Industries Ltd. which expired in October 2025. The term of the New Rotem Maintenance Agreement is 12 years from the end of the term of the existing Rotem maintenance agreement, or the completion of the required maintenance work, and no later than 20 years from the end of the term of the existing Rotem maintenance agreement. Under the New Rotem Maintenance Agreement, Mitsubishi undertakes towards Rotem to maintain a certain level of availability of the components relevant to the power plant and other parameters related to the performance of the relevant components in the power plant (including an undertaking regarding emissions). Maintenance work is to be executed in the power plant every 25,000 working hours (approximately three years). In addition to the signing of the New Rotem Maintenance Agreement, Rotem undertook to acquire new equipment for the power plant at a cost of approximately EUR 8 million. Hadera. In June 2016, Hadera entered into a maintenance agreement with General Electric International Ltd. (“GEI”), or GEI, and GE Global Parts & Products GmbH pursuant to which these two companies provide maintenance treatments for the two gas turbines of GEI, generators and auxiliary facilities of the Hadera plant for a period commencing on the COD until the earlier of: (i) the date on which all of the covered units have reached the end-date of their performance and (ii) 25 years from the date of signing the service agreement. 92 Zomet. In September 2018, Zomet signed an engineering, procurement, and construction agreement (EPC) with PW Power Systems LLC, a partnership registered in the United States (“Pratt and Whitney” or the “Contractor”), of the Mitsubishi Hitachi Power Systems group, for construction of the Zomet Project (the “EPC Agreement”). The EPC Agreement is a “lump sum turnkey” agreement, whereby contractor committed to construct the Zomet Project in accordance with the technical and engineering specifications provided and including commitments of the Contractor to perform certain work in the project, as stipulated in the EPC Agreement. The contractor is a manufacturer of gas turbines. The Contractor also committed to provide certain maintenance services in connection with the power plant, for a period of 20 years commencing on its commercial operation date. At the time of the entering into the agreement, total consideration was estimated at approximately $300 million, including the consideration for the Maintenance Agreement for the entire term of the agreement which is paid on an annual basis. Furthermore, the consideration in respect of the maintenance services may increase in line with the actually required maintenance. In December 2019, Zomet entered into a long-term maintenance agreement with PW Power Systems LLC. The consideration in respect of the maintenance may increase in line with the maintenance that will actually be required. Zomet may terminate the Zomet Maintenance Agreement after a period of 5 years from the power plant’s delivery date, subsequent to the terms and conditions set in the Zomet Maintenance Agreement. Pursuant to the agreement, PW will provide maintenance work on the Zomet plant generators, turbines, and additional equipment for a period of 20-years commencing on the COD of the Zomet plant. Gat. On January 29, 2017, the Gat Partnership and Siemens Israel Ltd. (“Siemens”) entered into an operating and maintenance agreement in connection with the Gat Power Plant (the “Gat Operating and Maintenance Agreement”). As part of the agreement, Siemens undertook to provide all operation and maintenance services to the Gat Power Plant, at a cost of approximately NIS 287 million (approximately $90 million), which is paid over the term of the agreement, in accordance with a formula set in the agreement. The term of the Gat’s operating and maintenance agreement is 20 years or 170 thousand operating hours from the commercial operation date, whichever is earlier, subject to early termination provisions in the agreement. Following the commercial operation of the power plant, a dispute arose between the parties regarding the Gat Partnership’s right to receive a discount on the quarterly payment to Siemens, in accordance with the provisions of the Gat Operating and Maintenance Agreement. Gat’s position is that a discount should apply to the payment, and Siemens disputed this position. The parties commenced an arbitration proceeding – in April 2025, the parties entered into a settlement agreement, which stipulates, among other things, that half of the amounts previously offset by Gat under the discount will be transferred to Siemens; the parties also agreed on the value of the annual discount for the remaining term of the maintenance agreement. The Gat Partnership will have the right to terminate the agreement after 2 major maintenance cycles under certain conditions. Gat will waive its first termination right after the first 60 thousand hours, which is expected to take place in 2026. Equipment supply agreements Equipment supply agreement for Hadera 2. In February 2026, Hadera 2 and GE Vernova entered into a binding agreement for the supply of the Hadera 2 power plant’s primary equipment, including the gas and steam turbines and ancillary equipment (the “Hadera 2 Equipment Supply Agreement”) and a maintenance agreement with respect to the equipment. Under the Hadera 2 Equipment Supply Agreement, GE undertook, among other things, to supply the primary equipment specified in the agreement on agreed dates and conditions. Furthermore, the Hadera 2 Equipment Supply Agreement includes certain provisions regarding the equipment’s performance, guarantees, caps and limitation of liability and GE warranty in respect of the equipment. GE’s undertakings and duties under the Equipment Supply Agreement are capped and are subject to conditions. Hadera 2 undertook to pay the agreed consideration in accordance with the Hadera 2 Equipment Supply Agreement on scheduled payment dates, some of which had already taken place, and which constitutes approximately 20% of the estimated project cost. Initially, the consideration is paid out of own sources and at a later stage it is also expected to be paid through a project finance agreement (subject to its signing). 93 Solar panels purchase agreement for the Ramat Bekka Project. In December 2024, OPC entered into an agreement to supply solar panels for the Ramat Bekka project with a global supplier (the “Panel Supplier”), with a capacity of up to 500 MW, at a total estimated cost of approximately $50 million. The purchase agreement provides that the Panel Supplier shall supply OPC with solar panels in accordance with purchase orders, at a fixed price (USD). In addition, the agreement includes provisions in respect of the solar panels’ technical specifications, ordering mechanisms, early termination provisions and terms and conditions thereof, supply dates, warranty terms and conditions, payment of advances to the supplier, and compensation in the event of a significant delay, as well as the collateral that OPC and Panel Supplier would provide to secure their contractual undertakings. According to the agreement, the solar panels are expected to be supplied in 2026-2028. EPC agreement for the construction of a private substation and a switching substation for Ramat Bekka. In January 2026, Ramat Bekka entered into an EPC agreement for a private substation and a switching station totaling approximately NIS 310 million, with Afcon Holdings Ltd. The agreement stipulates that the parties will have the right to terminate the work prior to the completion of the project, under certain circumstances and subject to the conditions set (including conditions set to the contractor in the event of failure to issue a notice to proceed order on a certain date). The construction works are contingent, inter alia, on financial closing of the Ramat Bekka Project, obtaining required permits and regulatory approvals. OPC estimates the payments under the agreement until the expected construction commencement date of the project to be in the tens of millions of shekels. Negotiation of a construction agreement for a photovoltaic facility for Ramat Bekka. OPC is currently working toward entering into an agreement with the photovoltaic facilities’ construction contractor, at an estimated total of approximately NIS 500 million; this agreement is expected to be under terms generally accepted in the sector. OPC has not yet entered into such an agreement, and there is no certainty as to its binding conditions, including with respect to dates, the parties' undertakings and the consideration amount payable to the contractor. United States CPV’s project companies are party to gas supply, transmission and interconnection agreements as well as maintenance and operating agreements and management agreements, as described above and below. CPV’s project companies with natural gas-fired power plants purchase natural gas from third parties pursuant to gas sale and purchase agreements. Service Agreements, Equipment Agreements and EPC Contracts The operating projects generally enter into long-term operating and maintenance agreements and services agreements with original equipment manufacturers and third-party suppliers for the maintenance and operation of the project facilities’ equipment. In connection with the projects under construction, CPV also enters into general purchase agreements and equipment supply agreements with original equipment manufacturers, as well as engineering and procurement contracts (EPC) for the construction of the power plant, including identifying and assembling special equipment in certain facilities. In respect of the Renewable Energy operations, on March 10, 2022, CPV entered into a framework purchase agreement of solar panels for a total capacity of approximately 530 MWdc. CPV has paid a down payment to the solar panels supplier considering termination date. The agreement further includes, among others, provisions regarding quantities, model, manner of delivery of the panels and termination. Since its execution, the agreement has been amended to, among other things, reallocate the total volume of panels among CPV Group’s solar projects and increase the number of installment payments as well as provisions regarding the termination of the agreement under certain conditions. In April 2025, CPV Renewable signed an additional amendment to the agreement, to increase the total number of the solar panels as part of the agreement by additional approximately 140 MWdc, while reducing the price per unit, adjustment of the timetables for supply of the panels to the timetables of the development projects, update of the deposit provided by CPV Renewable and reduction of the scope of the compensation that will apply to CPV Renewable in a case of early termination of the agreement. The total aggregate amount of purchases under the agreement may total up to approximately $208 million, out of which $155 million has been paid. The agreement is planned to be used for CPV’s solar projects with a total capacity of 670 MW. 94 In 2023, CPV Group started receiving deliveries of the solar panels and has currently received 425 MW and the remaining solar panels under the agreement were ordered for pipeline projects. Additional or increased tariffs levied on imports by the Trump administration from the beginning of 2025 may lead to increased costs for CPV Group’s equipment and construction costs (in all segments). Regional conflicts and geopolitical events impact ocean transport could lead to supply chain disruptions. There is no certainty as to the duration or scope of the trend. Changes in suppliers and raw materials Generally, in 2025, renewable energy solar panel prices have continued to decline compared to historical levels. For natural gas projects, prices for EPC contracts and gas turbines have increased mainly due to tighter supply chains, higher material/labor costs, longer lead time and higher demand. In 2025, the increasing demand for natural gas power plants and other generation facilities to support global electricity demand, in addition to other global supply chain issues, led to significant shortage of delivery slots and extended delivery dates for gas turbines and major electrical equipment for natural gas power plants. Such schedule and supply constraints, have led to market trend of increased and non-refundable down payments and/or reservation fees to secure the delivery date, while other development milestones are still pending. This trend affects CPV’s Low Carbon Projects under development and accordingly may require increased pre-construction non-refundable payments to secure delivery date for the equipment for the projects. In this context, the Shay project entered into an agreement for major electrical equipment and an agreement for gas turbines with global equipment suppliers, with the payments in aggregate of several tens of million dollars. Additional/increased tariffs levied on imports by the Trump administration from the beginning of 2025 led to increased costs for power plants and power generation facilities, including CPV Group’s equipment and construction costs as well as maintenance costs for operating projects (in all segments). Insurance OPC and its subsidiaries, including CPV, hold various insurance policies, including “all-risks” insurance. As of March 12, 2025, Rotem, Zomet, Gat, Hadera and the Hadera Energy Center are insured under, among others, the following insurance policies: “all risks” property insurance including mechanical breakage, loss of profit due to damage to the insured property, acts of terror and War (combined property and loss of profit insurance policy), third party liability insurance, employer liability insurance. The Sorek 2 generation facility is insured under a joint construction policy with IDE (who is constructing the desalination facility). OPC pays a portion of the premium in respect of the policy based on its share. The generation facilities at consumers’ premises have insurance coverage for their construction and operation stages (depending on the stage of the project). Furthermore, the liability insurance and the employers’ liability insurance are regulated under other policies taken out by OPC. OPC’s sites (similar to most private business activities in Israel) could be exposed to physical damage as a result of the War. The War’s potential effects, including events such as Iran’s attacks on Israel and attacks by hostile organizations in Yemen, might have an adverse effect on the availability of insurance policies to cover OPC’s assets in Israel in respect of war and terrorism risks, or on the terms of engagement in such policies. OPC extended such insurance policies in Israel through May 31, 2025. The insurance policies maintained by OPC and its subsidiaries may not cover certain types of damages or may not cover the entire scope and cost of damage caused and such policies include deductibles and exceptions as customary in the areas of activity. In addition, OPC or CPV may not be able to obtain insurance on comparable terms in the future. 95 Similarly, CPV Group holds various insurance policies for purposes of reducing the damage that could be caused to it as a result of occurrence of certain risks, including “all risks” insurance. The existing insurance policies of CPV Group may not cover certain damages or not cover the entire scope of the damage caused (and such policies include deductibles and exclusions as customary in the areas of activity). In addition, it is possible that CPV Group will not be able to obtain insurance under similar terms and conditions in the future. CPV Group could be adversely impacted if its projects suffer any damages that are not fully covered by insurance policies. Employees Israel As of December 31, 2025, in Israel, OPC had a total of 348 employees, of which 173 employees are in the OPC Israel division (including plant operation, corporate management, finance, commercial and other), and 72 are at OPC’s headquarters. Substantially all of OPC’s employees are employed on a full-time basis. The table below sets forth breakdown of employees in Israel by main category of activity as of the dates indicated: As of December 31, 2025 2024 2023 Number of employees by category of activity: Headquarters 72 73 55 Plant operation, corporate management, finance, commercial and other 101 98 114 OPC Total (in Israel) 173 171 169 Most of Rotem and Hadera power plants’ operations employees are employed under collective employment agreements. Rotem is currently negotiating with its employees the engagement in a revised collective agreement to come into force immediately upon the end of the term of the agreement. The term of the Rotem collective agreement ended on March 31, 2023, and a revised collective agreement was signed in respect of Rotem’s employees for a period of four years until March 31, 2027. At Hadera, the collective agreement applicable to OPC (with respect to approximately 75% of the employees) is in effect through the end of March 2026, and OPC has notified the relevant parties of its intention to commence negotiations for its renewal. Furthermore, following the announcement regarding the establishment of an employee representative body at the Zomet Energy power plant, negotiations are underway to reach a collective agreement for the employees who are members of this body, constituting approximately 50% of the power plant’s employees. United States As of December 31, 2025, CPV had a total of 175 employees. In general, CPV does not enter into employment contracts with its employees. All employees of CPV are “at-will” employees and are typically not physically present at the project companies facilities. Rather, day-to-day operations at the project facilities are performed by contractors who are employed directly by the applicable operation and maintenance service providers. Shareholders’ Agreements OPC Israel A shareholders’ agreement, entered into in January 2023, is in place between OPC and Veridis regarding OPC Israel. The shareholders’ agreement regarding OPC Israel includes customary terms and conditions, including, inter alia provisions regarding shareholder meetings, rights to appoint directors (such that OPC, as the controlling shareholder, has the right to appoint the majority of directors), and shareholder rights in case of share allocation. The shareholders’ agreement grants Veridis veto rights in connection with certain material decisions regarding OPC Israel, including: (i) changing the incorporation documents so as to adversely affect or change Veridis’ rights and obligations; (ii) liquidation; (iii) extraordinary transactions (as the term is defined by the Israeli Companies Law -1999) with related parties, with the exception of the exceptions set forth therein; (iv) entry into new substantial projects that are not included in OPC Israel’s area of activity; (v) a restructuring or a merger as a result of which OPC Israel is not the surviving company, subject to an exception in the case of a drag-along sale; (vi) appointing an independent auditor to OPC Israel or a material subsidiary thereof that is not one of the “Big Five” CPA firms; and (vii) approval of a transaction or project, in the agreement in which the planned investment amount is highly material, in accordance with criteria set forth, and subject to exceptions. The shareholders’ agreement stipulates that decisions on these matters require a special majority (of 87.5% in a shareholders meeting, and the consent of at least one director representing Veridis on OPC’s board of directors), as long as Veridis’ stake does not fall below the threshold set in the Shareholders’ Agreement. 96 The agreement provides for additional rights in the event of the sale of OPC Israel’s shares held by any of the parties, such as the right of first refusal, the tag-along right, the drag-along right—all in accordance with the terms and conditions set forth. OPC Power Ventures In October 2020, OPC signed a partnership agreement with three institutional investors in connection with the formation of OPC Power Ventures (the “Partnership”) and acquisition of CPV by the Partnership. The limited partners of the Partnership following increases in the investment commitment from 2025 until March 11, 2026 are: OPC (approximately 7.0% interest); institutional investors of Clal Insurance Group (12.75% interest); institutional investors of Migdal Insurance Group (12.75%) (together, the “Financial Investors”) and a company from the Poalim Capital Markets Group (4.5%). The percentages above do not reflect participation rights in the profits allocated to the CPV managers. The total balance of investment undertakings and shareholders’ loans advanced by all partners under the facility is estimated at approximately $100 million (excluding the guarantee facility). In February 2026, the process of increasing partners’ investment commitments to fund an investment in CPV Group was completed with respect to the financial closing of the Basin Ranch project and transactions to increase stakes in the operational gas-fired power plants by a total of approximately $502 million (a total of approximately $232 million in respect of securing letters of credit, which were provided/promised by OPC, with respect to the construction of the Basin Ranch project). Taking into account the additional commitment amounts and the acquisition of an additional immaterial stake by OPC from one of the financial investors – OPC’s (indirect) holding stake in CPV Group was approximately 70.69% as of December 31, 2025 and approximately 71.09% as of March 12, 2026. An entity wholly-owned by OPC acts as the general partner of the Partnership. Certain material actions require approval of a majority or special majority (according to the specific action) of the investors in the Partnership. These actions include interested party transactions, certain limits on transfers of partnership interests, including sale of CPV Group in its entirety or a public offering (which do not meet certain minimum threshold requirements), a sale of significant portion of CPV Group’s assets during the course of a calendar year, subject to the terms and conditions, tag along rights for the Financial Investors, drag along rights, and rights of first offer for OPC and the Financial Investors in the case of transfers by the other party. Furthermore, as long as OPC is the controlling shareholder of the Partnership’s general partner, any separate activity by OPC in the Partnership’s activities in the U.S. shall require approval by a special majority of the other partners. The general partner is entitled to management fees and carried interest, subject to meeting certain achievements. OPC and the Financial Investors have entered into put and call arrangements, with the Financial Investors being granted put options and OPC being granted a call option (if the put options are not exercised), with respect to their holdings in the Partnership. These options are exercisable after 10 years from the date of the CPV acquisition (i.e., in January 2031) and to the extent that up to such time the Partnership interests are not traded on a recognized stock exchange. The consideration with respect to the exercise of the options will be determined in accordance with the arrangements agreed upon regarding the value measurement method. OPC shall have the right to pay the exercise price (at its discretion) in OPC shares based on their average price on the stock exchange immediately prior to the exercise. Legal Proceedings For a discussion of significant legal proceedings to which OPC’s businesses are party, see Note 26A to our Consolidated Financials Statements. 97 Industry Overview Electricity generation and supply in Israel In general, the Israeli electricity sector is divided into several segments reflecting different stages of the electricity supply chain - from the generation stage to the sale to the end customer: the generation segment; the transmission segment (transmitting electricity from generation facilities to switching stations and substations through the electricity transmission grid); the distribution sector (transmitting electricity from substations to consumers through the distribution grid including high voltage and low voltage lines), the supply sector (sale of electricity to private customers) and the System Operator. Subject to restrictions under the Electricity Sector Law, none of the activities provided in the Electricity Sector Law may be carried out except pursuant to an activity in each of the segments requiring a relevant license. Pursuant to Electricity Sector Status Report for 2024, the installed electricity production capacity in Israel (of the IEC and independent producers), was approximately 17,735 MW excluding renewable energies, and approximately 6,870 MW of renewable energies. According to publications of the EA, in 2024 demand for electricity increased by 4.4% (calculated annually). According to the Electricity Sector Report, in 2024, the sectoral generation amounted to 80.4 TWh; in 2030, the annual generation forecast is expected to stand at 94.6 TWh. The Israeli electricity market includes a number of key participants: the Ministry of Energy, the EA, the IEC, Noga, independent power producers and suppliers and electricity consumers. Ministry of Energy The Ministry of Energy regulates the energy and natural resources markets of the State of Israel: electricity, fuel, cooking gas, natural gas, energy conservation, water, sewerage, oil exploration, minerals, scientific research of the land and water, etc. The Minister of Energy has powers under the Electricity Sector Law, including regarding licenses and policy setting on matters regulated under the law and operates to ensure the markets’ adequate supply under changing energy and infrastructure needs, while regulating the markets, protecting consumers and preserving the environment. The EA The EA is subordinated to the Ministry of Energy and operates in accordance with its policy. The EA has the authority to grant licenses in accordance with the Electricity Sector Law, supervise license holders, set electricity tariffs and criteria for them, including the level and quality of services required from “essential service provider” license holders, supply license holder, a transmission and distribution license holder, an electricity producer and an independent power producer. Thus, the EA supervises both the IEC and private producers. For further information on related EA tariffs, see “—Industry Overview— Electricity generation and supply in Israel.” For further information on the effect of EA tariffs on OPC’s revenues and margins, see “Item 5. Operating and Financial Review and Prospects—Material Factors Affecting Results of Operations—Activities in Israel—EA Tariffs.” IEC and Noga IEC. The IEC supplies electricity to most of the customers in Israel in accordance with licenses granted to it under the Electricity Sector Law, and transmits and distributes almost all of the electricity in Israel. In general, the IEC is responsible for the installation and reading of the electricity meters of electricity consumers and generators and for transfer of the information to Noga and suppliers in accordance with the decisions of the EA. Noga. Noga is a government company is in charge of the management of the electricity system in the generation and transmission segments, including constant balancing of the supply of and demand for electricity, planning of the transmission system, including drawing up a development plan for the transmission and generation segments. Pursuant to the Electricity Sector Law, the IEC and Noga are each defined as an “essential service provider” and as such, they are subject to the requirements and tariffs set by the EA. 98 Independent Power Producers (IPPs) Activity by IPPs, including the construction of private power stations and the sale of electricity produced therein, is regulated by the Electricity Sector Regulations (Conventional Independent Power Producer), 2005 (the “IPP Regulations”) and the Energy Sector Regulations (Cogeneration), 2004 (the “Cogeneration Regulations”), as well as the rules, decisions, and standards established by the EA. Regarding certain matters, unique regulation applies to Rotem, which in 2024 was consolidated in multiple respects with the regulation applicable to generation facilities authorized to conduct bilateral transactions. According to the Electricity Market Status Report, as of 2024, independent power producers (including OPC power plants), including those using renewable energy, active in Israel have an aggregate generation capacity of approximately 15,770 MW, constituting 64% of the total installed generation capacity in Israel. According to the Electricity Market Status Report, at the end of 2030, the market share of the independent power producers, including renewable energies, is expected to be approximately 78% of the total installed capacity in the sector. In generation terms, in 2030 the market share of the independent power producers (including OPC power plants), and including renewable energies, is expected to be approximately 79% of the total generation in the market. Set forth below are the key electricity production technologies used by private producers in Israel relevant to OPC’s activity: • Conventional and cogeneration technology—electricity generation using fossil fuel (natural gas and diesel oil as a backup). As of December 31, 2024, the total installed capacity with these technologies which is primarily operated by the independent producers, is approximately 8,600 MW. Gas-fired combined cycle generation facilities are planned to be operational during most hours over the year. Conventional open cycle power plants (the “peaker power plants”) are generally planned to operate for a number of hours during the day; these power plants are operated when the demand for electricity exceeds the supply–- whether due to demand peaks, as backup in case of malfunctions in other generation facilities, or as a supplement when solar energy is unavailable—whether in the early morning hours or after dark. Electricity using cogeneration technology is generated using facilities which produce energy from a single source - both electricity and useful thermal energy (steam). • Renewable energy—electricity generated from, inter alia, sun, wind, water or waste. In January 2026, the EA published a comprehensive work for public comment, which recommended to increase the renewable energy production targets to 35% by 2035, instead of previous target of 30% by 2030. As of the end of 2024, the installed capacity of renewable energy generation facilities was 6,890 MW, with actual generation constituting approximately 14.6% of total actual consumption in Israel in 2024. In recent years, there has been an uptick in the entrance of electricity producers and generation facilities that use renewable energies in the electricity generation market, including solar energy, wind energy, and storage; that use the grid resources. The EA as part of the Report on the Status of the Renewable Energy Targets in the Electricity Sector in 2024 stated that as at the end of 2024, the rate of actual consumption of renewable energy in the Israeli economy was 14.7%; the rate of renewable energy installed capacity out of total capacity in Israel as of the end of 2024 was 27.2%. • Energy storage—this is possible through a range of technologies, including, among others, pumped storage, mechanical storage (for example compressed air) and chemical storage (for example batteries). Based on the electricity system’s planning paper, the use of this technology is currently negligible; however, it is expected to increase significantly in the forthcoming years due to the need for storage facilities as a result of the anticipated increase in renewable energies, among other things. In particular, based on study conducted by EA, compliance with the target for renewable energies up to 2030 will require construction of storage facilities with a capacity of thousands of MWh, deriving from the readiness of the technology and the economic feasibility of its use. OPC is working to integrate energy – storage facilities into its asset portfolio, including, among other things in the Ramat Bekka Project and in other solar projects currently in the planning stages. Independent Power Suppliers The electricity suppliers operate under supply licenses, by virtue of which they are permitted to sell electricity –- to consumers in accordance with the terms and conditions of the licenses and the regulations applicable to them. As part of the Electricity Sector Reform, the EA opened the supply segment to competition passing several resolutions, including in respect of issuing supply licenses to virtual suppliers (with no means of production, in addition to the existing conventional suppliers, which received supply licenses in addition to their electricity generation activity) to regulate the purchase - from Noga - of electricity by suppliers and producers on the distribution grid for the purpose of selling it to consumers. 99 Electricity Consumers Electricity consumers are the main driving force of the electricity sector; their consumption dictates the required scope of development. In accordance with the Electricity Sector Report, approximately 74.9 TWh was consumed in 2024, of which approximately 23.8 TWh by household consumers, 19.5 TWh by commercial consumers, 15.3 TWh by industrial consumers and the remainder by other consumers. Recently, including due to the introduction of electric vehicles, the status of the electricity consumers–- as proactive actors–- has strengthened. OPC believes, the steps taken by the EA to open up the supply segment to competition, including decisions regarding installation of smart meters and licensing suppliers without means of production, has increased the number of entities operating in the household supply segment and the scope of consumption associated with independent suppliers. The generation component and changes in the IEC’s cost In accordance with the Electricity Sector Law, the EA determines tariffs charged by the IEC, including the rate of the electricity generation component, in accordance with the costs principle and the other considerations provided for in the Electricity Sector Law, as applied by the EA. The generation component is based on, among other things, the IEC’s fuel costs, comprising mainly of the IEC’s gas and coal costs, the costs of purchasing electricity from independent producers and the IEC’s capital costs, and is affected, among other things, by the EA’s policy on classification of costs to either the generation component and the IEC’s system costs. The generation component may also vary in accordance with other IEC expenses and revenues and in 2025, it was also affected by additional factors, such as proceeds from the sale of power plants. As from 2026, the generation component will be affected by IEC’s and Noga’s actual costs, as detailed below in the price band mechanism under the new tariff structure. Under the agreements with private customers, involving OPC’s active generation facilities in Israel, OPC charges the load and time tariff (the “DSM Tariff”), net of a discount in respect of the generation component. Since the electricity price in the agreements between Rotem, Hadera and Gat (and of the generation facilities) and their customers is impacted directly by the generation component (such that a decline in the generation component would generally lower the profitability and vice versa), and since the weighted generation component is linked to the natural gas price in accordance with the gas supply agreements of OPC in Israel (subject to a minimum price), OPC is exposed to changes in the generation component and the components and costs which may affect it. In addition, OPC is exposed to changes in the methodology for determining the generation component and recognizing the IEC’s costs by the EA. In general, an increase in the generation component has a positive effect on OPC’s results. In accordance with the tariff it charges, Zomet is not exposed to changes in the generation component. The summer on-peak (August) high voltage tariff for 2025 indicates that the generation component in 2025 accounted for about 88% of TAOZ. In addition, the TAOZ includes system costs at the rate of 10% and public utilities at the rate of about 2%. On January 1, 2025, an annual update of the tariff for 2025 came into effect. Revision to the electricity tariff structure In November 2024, the EA published a call for proposals on proposed changes to the tariff structure, which specified proposed updates to the principles for determining tariffs for Israel Electric Corporation consumers and suppliers, in view of the changes in the electricity sector, as reviewed by the EA (the “Call for Proposals”). The call for proposals focuses on three main proposals: (1) a proposal to change the methodology for determining the generation component such that it will be determined based on a variable component based on the system marginal price (“SMP”), i.e., the competitive market price, plus a normative fixed component to be determined by the EA using a shadow pricing model or based on actual economic costs; (2) a proposal to apply an economic signaling mechanism of pricing external costs of emissions such that it will be part of the marginal cost; and (3) a proposal to update the tariff automatically and more frequently according to the changes in the measures. 100 According to the Call for Proposals, the proposals may be implemented gradually or comprehensively. Following on the Call for Proposals, in September 2025, the EA published a hearing entitled Revision of the Tariff Structure for Electricity for Consumers of Israel Electric Corporation, in which the EA proposed to partially implement the change outlined in the call for proposals and, among other things, to determine that the structure of the generation component will be modified such that, as from January 1, 2026, the generation component will be split into a fixed component and a variable component, based on the 2025 tariff costs (without incorporating the marginal clearing price (“MCP”) or pricing of external emission costs at this stage). MCP, i.e. the marginal cost is calculated on a half-hourly basis by the System Operator. In the original call for proposals, reference was made to the SMP, and currently the System Operator is working to revise the methodology; the new methodology is called MCP. As stated in the explanations, the bifurcation of the components was designed, among other things, to prepare the sector for a future segregation between them, should it be decided at a later stage that the variable component will be based on the MCP price. In December 2025, the EA published its resolution entitled “Revision of the Electricity Tariff Structure”. Under the resolution, the EA implemented some of the changes, which were proposed in the call for proposals, and noted that some of them will be implemented in the future. Among other things, under the resolution, the generation component’s structure was split into a fixed component and a variable component without applying the MCP (i.e., the marginal cost calculated on a half-hourly basis by the System Operator) - under the variable component and without pricing the external costs of emissions at this stage. Additionally, the resolution prescribes a starting-point tariff for each of the segments based on the 2025 tariffs and a mechanism was set for automatic revisions to the tariffs, without obtaining the approval of the EA’s plenum, every six months (on January 1 and July 1), from January 1, 2026 to December 31, 2028 (the “Tariff Period”). The tariff revision mechanism, which is based on measures and coefficients detailed in the resolution – such the exchange rate and consumer price index - and is designed to provide certainty and transparency during the Tariff Period. In order to ensure that the tariff does not substantially deviate from the actual costs, the EA has set a price band mechanism designed to enable a tariff revision when differences exceed a certain amount (NIS 750 million for the IEC and NIS 350 million for Noga) and additional bands for each segment of activity and the IEC and Noga jointly, in accordance with a cost control which the EA will carry out at the end of each year. The EA noted that by the end of 2028 it will publish a resolution on revision of the tariff structure for the following years; it further noted that during 2026 the EA is expected to discuss the revision of the generation and system segment tariffs set in this resolution, from a three year perspective. In December 2025, the generation component for 2026 was set at approximately 28.90 agorot (subject to periodic revision as stated above), using an exchange rate of NIS/USD 3.3. The Effect of changes in foreign exchange rates on the generation component and natural gas prices in accordance with the agreements. In Israel, OPC is exposed to changes in exchange rates (for details on the effect of changes in exchange rates on, see “Item 5. Operating and Financial Review and Prospects—Material Factors Affecting Results of Operations— Changes in Exchange Rates.” In 2025, the generation component is set, in part, in accordance with the IEC’s fuel costs (mainly coal and gas), which are denominated in USD and, accordingly the generation component is partly affected by changes in foreign exchange rates. The price of natural gas in accordance with Rotem’s natural gas supply agreement with the Tamar Group is linked in part to the USD exchange rate and is subject to a minimum incremental USD price. When the gas price is equal to the Minimum Price in the Rotem Agreement, OPC has greater exposure to changes in the exchange rate of the USD versus the NIS, compared with a situation wherein the price of natural gas exceeds the Minimum Price. The price of the natural gas in the Hadera and Gat agreements is denominated in USD and, therefore, it has full exposure to changes in the currency exchange rate, subject to a minimum incremental USD-denominated price. In 2025, the gas price in Hadera and Gat’s gas agreements was under the Minimum Price for 6 months, such that they paid the Minimum Price, and for 6 months - their price exceeded the Minimum Price. In addition, in 2026, if the generation component will not change, the gas price under the Hadera and Gat agreement is expected to exceed the Minimum Price, which stands at the lowest tier. In addition, the price in the Energean agreements is fully linked to the USD. The gas price in Sorek 2’s natural gas agreement is denominated in USD. 101 In addition, if the price of gas is equal to the Minimum Price in the Rotem Agreement, reductions of the generation component will not lead to lower costs for the natural gas consumed and will have an adverse effect on OPC’s profitability. In 2025, the gas price in the Rotem agreement with Tamar was above the Minimum Price during six months of the year. Given the USD exchange rate environment, and according to the annual update of the generation component for 2026, the price of gas is expected to exceed the Minimum Price in 2026 (provided there are no changes to the generation component). Regulation governing OPC’s activity in Israel. OPC’s activities in Israel are regulated by the provisions of the law, which include, among other things, the following: The Electricity Sector Law, which includes among other things provisions regarding licensing of the various electricity sector activities and players, the provisions regarding essential service license holders and requirements thereof, as well as provisions relating to the EA, its composition, powers and roles and the regulations promulgated thereunder, Government policies and resolutions, covenants and decisions of the EA, decisions of the Ministry of Energy, the Natural Gas Sector Law, 2002 (the “Natural Gas Sector Law”) and decisions of the Natural Gas Authority and the Natural Gas Council, the Economic Competition Law, 1988 (the “Economic Competition Law”) and decisions of the EA, the Market Concentration Law, the Companies Law and the regulations promulgated thereunder, as well as regulation pertaining to business licensing, planning and building and environmental protection. Market Concentration Law Sectoral concentration According to the Market Concentration Law, upon issuance of a right (including an electricity generation license in certain capacities) and when determining the terms and conditions for this right, the entity granting the right (which is primarily the EA, the Minister of Energy or IEC) must take into account, in addition to every other consideration it is required to address, considerations of the advancement of competition in the sector. In the event that the interest is listed in the list of rights issued by the Commissioner, for purposes of sector’s market concentration considerations, the entity granting the right may not grant such right except after taking into account advancement of competition in the sector and consulting with the Competition Commissioner. In addition, pursuant to the Market Concentration Law, an entity which is authorized by the applicable law to issue the right to determine rules in its matter, is permitted, after it took into account sectorial business competition considerations to determine rules regarding issuance of the interest that could boost sectorial competition. Regarding the license included in the list of rights (including an electricity generation or storage license above a certain capacity, all as provided in the list of rights), and to the extent the rules were provided in consultation with the Concentration Commissioner and in accordance with the provisions of the Market Concentration Law, the entity granting the right is permitted to issue the right even without consultation with the Commissioner. Publication by the Israel Competition Authority regarding the assessment of horizontal market power in the Israeli wholesale electricity market Further to the expiry of the Market Concentration Regulations, on December 28, 2025, the Israel Competition Authority published a draft for public comment of a study, which includes two economic methodologies focusing on an assessment of the incentive and electricity producers’ ability to adopt a strategy of reducing the quantities of electricity they supply to the economy in order to increase the system marginal price and thereby maximize their profits. Under the EA’s resolution titled “Eligibility of Hadera 2 for a Generation License”, the EA used the competitive residual demand model referred to in the draft study. The methodologies set in the study have not yet been translated into legislation or a binding legal source, and by nature, OPC is unable to assess, at this stage, what effect the study will have (if any) (and in particular its final version, once and if published) on its activities in the field. Aggregate concentration In addition, in accordance with the sectoral concentration consideration under the Market Concentration Law, upon issuance of a right to a concentrated entity (an entity included in the list of the concentrated entities which is prepared in accordance with the Market Concentration Law), the party issuing the rights must take into account aggregate concentration considerations while consulting with the Market Concentration Committee, as defined in the Market Concentration Law. OPC is included in the list of concentrated entities under the Israel Corporation Ltd. group (the “Israel Corporation”) despite the fact that Israel Corporation has no holdings in OPC, including for purposes of aggregating the electricity generation activity of other companies of the Israel Corporation group (including ICL Group Ltd. (“ICL”)) with the electricity generation activity of OPC, Kenon and OPC’s subsidiaries for the purpose of aggregate concentration. The list of concentrated entities also includes Mr. Idan Ofer, who is the beneficiary in a trust which indirectly holds Kenon, as a concentrated entity, and also includes under the Israel Corporation Group (which is held indirectly by the abovementioned trust) several other companies defined as concentrated entities. Pursuant to the Market Concentration Law, such aggregate concentration considerations apply in case of a request for a generation license for the building and operation of a power plant with a capacity of more than 175 MW which is connected to the transmission grid. 102 Additional provisions of the Market Concentration Law After having been included in the list of significant non-financial corporations in previous years, in the list of non-financial corporations as of February 2025, OPC and Kenon are no longer defined as significant non-financial corporations as per the Market Concentration Law. A significant non-financial corporation (as well as the holders of the means of control therein) is subject, among other things, to various restrictions by virtue of the Market Concentration Law, mainly restrictions on holding significant financial entities, and restrictions on holdings of significant financial entities in significant non-financial corporations, as well as restrictions on cross-tenure as a director in a significant non-financial corporation and a significant financial corporation. Furthermore, upon becoming a publicly-traded company and as long as Kenon constitutes a reporting corporation in accordance with the Securities Law, in accordance with the Market Concentration Law, OPC constitutes a “Second Tier” company and therefore may not control a “different tier company” as defined in the Companies Law. Such provision restricts OPC’s ability to list securities of OPC’s subsidiaries for trading on the stock exchange. Provisions of the Market Concentration Regulations The Electricity Sector Regulations (Promotion of Competition in the Generation Segment) (Temporary Order), 2021 (the “Market Concentration Regulations”) were published in December 2021 under a temporary order for three years, such that they expired in 2024 and a new temporary order and/or new regulations on the matter have yet to be published. Pursuant to the Market Concentration Regulations, a person will not be granted a generation license or approval in accordance with Sections 12 or 13 of the Electricity Sector Law if following the issuance, the person will hold generation licenses or connection commitment for gas-fired power plants the total capacity of which exceeds 20% of the planned capacity for each type of power plant. The planned capacity for 2024 for gas-fired power generation units is 16,700 MW. In the EA Resolutions Nos. 69505 and 68607 (dated March 18, 2024) entitled “Competency of the Sorek Tender Bidders” (the “Competency of the Sorek Tender Bidders Resolution”), the EA assessed competitiveness relative to a higher capacity and since - under the resolutions - the Sorek Power Plant is expected to commence commercial operation in 2028, the EA also assessed the holding rates with respect to gas-fired installed capacity regarding which construction plans are in place through the commercial operation of the Sorek Power Plant, which stands at 18,926 MW. Pursuant to the regulations, notwithstanding the above, the EA may grant such a generation license or approval on special grounds which shall be recorded (after consultation with the Israel Competition Authority) and for the benefit of the electricity sector. Furthermore, the EA may refrain from granting a generation license or from approving a connection to the grid if it believes that the allocation is likely to prevent or reduce competition in the electricity sector after taking into account additional considerations, including the impact of holdings of a person in other generation licenses that do not constitute a holding of a right as defined in the regulations, the impact of joint holdings in companies with a holder of other rights, as well as the impact of holdings of a person in holders of licenses which were granted under the Natural Gas Sector Law. According to the regulations, an “interest holder” is an interested party in a corporation for which the interest was granted, whereby - for this purpose - an interested party in a corporation who is an interested party in a corporation for which the interest was granted will also be considered an interested party in the corporation for which the interest was granted. Pursuant to Competency of the Sorek Tender Bidders Resolution, the EA determined that the holdings of institutional entities (as defined in the Supervision of Financial Services Law (Insurance), 1981) holding up to 20% (directly or indirectly) of a corporation applying for license, will not be counted, for reasons detailed in the resolution. For the purpose of calculating the holdings in rights or a connection commitment, a person shall be deemed a holder with respect to the entire installed capacity of the generation license or the connection commitment. The EA resolutions regarding sectoral competition and aggregate concentration, indicate that the EA continues to operate in accordance with the methodology set out in the Market Concentration Regulations, even though they expired, and under the qualitative considerations, the following factors will be taken into account: the capacity participating in the market model, additional holdings in the electricity sector, holdings in holders of licenses awarded under the Natural Gas Sector Law, 2022, or holders of ownership stakes as defined in the abovementioned law, and the effect of holdings in other corporations, which are also held by others who hold other rights in the electricity sector. OPC believes that the EA is considering the advancement of revised regulations on the subject, which may set various and/or additional arrangements to those included in the Market Concentration Regulations (including regarding technologies, relevant rates, etc.). There is no certainty regarding the promulgation of revised regulations or arrangements, which will be set there under. In accordance with the Market Concentration Law, in the absence of revised regulations, industrial concentration is expected to be addressed under specific resolutions. 103 The natural gas-fired capacity attributed to OPC (including the capacity attributed to ICL Group Ltd. and including conditional licenses) totals to approximately 1,500 MW (including Sorek 2 without weighting Hadera 2), in the context of the Market Concentration Regulations in accordance with EA’s resolution entitled “Eligibility of Dalia 2 and Hadera 2.” In accordance with the resolution, the natural gas-fired capacity attributed to OPC, including with respect to Hadera 2 is approximately 2,128 MW, taking into account only a 670 MW capacity due to the limitation on transmission to the grid until July 2035 as determined in Resolution No. 69407 of the EA of August 12, 2025. Resolution entitled Eligibility of Dalia 2 and Hadera 2 to Receive a Production License in Terms of Industry Competitiveness and Aggregate Concentration Further to EA assessment in its resolution, the EA notes that subject to certain conditions determined in the EA’s resolution, Hadera 2 will comply with the industry competitiveness conditions. According to EA’s resolution, the approval as to non-existence of industrial concentration will be subject to the condition that by June 1, 2028 or until commercial operation of one of the power plants, whichever is earlier, Dalia 2 and Hadera 2 will ensure that Barak Group, which holds both the Dalia Group, which is expected to build Dalia 2 (indirectly), and Veridis, which owns OPC Israel, which is expected to construct Hadera 2, will cease to be an interested party in OPC Israel, and that within 60 days of the EA’s resolution, the Barak Group will transfer its surplus holdings (over 5%) to OPC Israel to be held in trust. After taking into account aggregate concentration considerations, the EA determined that there is no impediment to the allocation of the right to OPC Israel, in accordance with the agreed outline. The EA’s resolution will be an additional condition, beyond the conditions required under the licenses, for obtaining the EA’s approval for financial closing. Publication by the Israel Competition Authority regarding the assessment of horizontal market power in the Israeli wholesale electricity market Further to expiry of the Market Concentration Regulations, on December 28, 2025 the Israel Competition Authority published a draft for public comment of a study, which includes two economic methodologies focusing on an assessment of the incentive and electricity producers’ ability to adopt a strategy of reducing the quantities of electricity they supply to the economy in order to increase the system marginal price and thereby maximize their profits. Under the EA’s resolution entitled “Eligibility of Hadera 2 for a Generation License”, the Israel Competition Authority used the competitive residual demand model referred to in the draft study. The methodologies set in the study have not yet been translated into legislation or a binding legal source, and by nature, OPC is unable to assess, at this stage, what effect the study will have (if any) (and in particular its final version, once and if published) on its activities in the field. Natural gas Natural gas serves as the primary raw material for electricity generation in this area of activity. During 2025, the active power plants acquired gas mainly from the Karish Tanin Reservoir, which is held by Energean, and from the Tamar Group. Pursuant to the Zomet Regulation (Regulation 914), the latter may receive the gas required for its operations by means of: (1) signing a gas agreement; (2) signing another agreement for supply of natural gas (for example, purchase of gas from another reseller or purchase of gas from other gas consumers) which permits supply of gas to the facility during all hours of the year; (3) if Zomet is unable to supply gas to the power plant during all hours of the year in accordance with alternatives (1) and (2) above, separately or jointly, it will receive gas based on the directives of the System Operator as part of Regulation 914. OPC meets Zomet’s demand for gas under the gas agreements into which OPC has entered and/or will enter. 104 The Gat Power Plant purchases some of the natural gas required for its activity from the Tamar Reservoir, under a separate agreement. In connection with OPC’s consumer on-site facilities, the required gas was purchased or is expected to be purchased under the agreements in which OPC had engaged and/or will engage. The Sorek 2 facility is expected to purchase some of the natural gas required for its operation from the Leviathan Reservoir as part of arrangements with the desalination facility. The remaining gas quantities which will be required for the operation of the generation facility are expected to be purchased through gas purchase agreements into which OPC entered and/or will enter. From time to time, OPC enters into additional gas sale and purchase agreements for its operations, and as an auxiliary part of the electricity and energy generation and supply activity. For details regarding the gas agreements entered into by OPC’s power plants, see “Item 4.B Business Overview—Our Businesses—OPC’s Business—OPC’s Raw Materials and Suppliers”. The electricity generation activity in the area of activity may be impacted by disruptions to the capacity or supply of the natural gas. In case of a continuous failure with respect to the supply of natural gas, OPC power plants in Israel must be ready to generate electricity by means of use of alternative fuel (e.g., diesel fuel). Due to the existence of three natural gas reservoirs, the risk of a general failure with respect to supply of gas in the Israeli economy has been mitigated to certain extent, compared with the situation of a single supplier of gas in the economy, which was previously the case. Disruptions in the availability or supply of natural gas in the gas reservoirs with which OPC entered into natural gas purchase agreements, and market prices of natural gas in Israel (including production from Israel by the local gas suppliers) as shall be from time to time, may affect the costs accrued to OPC in respect of acquisition of natural gas. For details regarding the effects of the War on the Tamar Reservoir, see “Item 3.D Risk Factors—The War may affect OPC operations in Israel— Uninterrupted supply of natural gas to the power plants.” Hadera and Zomet power plants are subject to Covenant 125 (as discussed below), which concerns natural gas shortages in Israel, and which prescribes, among other things, the System Operator’s power to issue guidance on the use of diesel fuel in the electricity sector at times of gas shortages, and that a producer which produced electricity using diesel fuel according to such guidance of the System Operator should be compensated in respect of the difference between the cost of production using diesel fuel and the cost of production using gas, which is known to the producer. OPC believes, based on past experience, that Covenant 125 also applies to the Rotem Power Plant; the EA has informed that its position on the subject is different, and OPC informed the EA of its position regarding this matter. In accordance with Hadera’s agreement with Infinya, in case of shortage of gas, and insofar as Infinya instructs Hadera to continue operating, arrangements were provided for operating the power plant using an alternative fuel and the netting in respect thereof. Energy Sector Targets in Connection with Reducing Greenhouse Gas Emissions and the amendment of the Excise Tax on Fuel Ordinance Further to a previous hearing entitled “Bilateral Market Regulation for Generation and Storage Facilities Connected to or Integrated into the Transmission Grid,” in May 2025, the EA published a resolution entitled Bilateral Market Regulation for Generation and Storage Facilities Connected to or Integrated into the Transmission Grid. The regulatory scheme will apply from January 1, 2026 to renewable energy production facilities co-located with storage (it has been determined that the facility will be required to meet a storage capacity ratio for installed production capacity of up to 7) which will receive tariff approval by June 1, 2027 or up to a cap of 2,000 MW. In accordance with the resolution, renewable energy generation facilities, including those co-located with storage, were allowed to enter into capacity transactions with virtual suppliers. The availability transaction shall entitle the supplier to buy energy at the half-hourly SMP at any hour, up to the total availability certificate the supplier purchased from the producer. The power specified in the capacity certificate will be determined in accordance with the capacity credit. The capacity credit for a renewable energy facilities co-located with storage of 4 or 5 hours of offloading, which will receive tariff approval under the initial quota of the regulation, will be at a rate of 60% and 67%, respectively, through 2036. Such a storage facility will operate in the energy market using the central loading method. A producer, except for an independent storage producer, which will not allocate to suppliers all the capacity specified in its capacity certificate, may request from the System Operator a capacity tariff of 1.75 agorot divided by the capacity credit set for the facility - non-linked - with respect to the capacity not allocated to a supplier, provided that the producer will not be able to allocate this capacity tariff to an independent supplier for 12 months. The Ramat Bekka Project, which is under advanced development stages, is expected to operate under this regulation (subject to a place within the quota, obtaining the appropriate tariff approval, completing the construction of the facility and operating it). Under the resolution, the EA also set a quota for independent storage facilities and waste energy reclamation facilities. The EA notes that as it extends to conventional generation units, the regulatory scheme will replace Regulation 555 (as discussed below), which comprises the regulatory framework for consumer-sited generation facilities. 105 With respect of 2026-2028, the EA determined a fixed increase coefficient on the energy component of the generation component at an annual rate of 1.79% due to the effect of the excise-tax increase. Development of the independent electricity market in Israel In recent years, the Israeli government completed key measures to transfer parts of the electricity generation and supply in Israel from IEC to independent producers and suppliers and to increase competition in these segments. The entrance of independent power producers and suppliers has led to a significant decrease in the IEC’s market share in terms of electricity generation and sale of electricity to large electricity consumers (high and medium voltage consumers). The generation segment – as of 2024, the IEC’s share amounted to 41% of the generation segment in terms of actual generation. According to the forecasts of the EA, in 2030, most of the electricity (approximately 77%) will be generated by independent producers using gas and renewable energies. The supply segment – in 2024, the market share of the independent suppliers reached approximately 35% of the economy’s consumption where most of the electricity for the industry is supplied by independent suppliers and the switching of household consumers to independent suppliers has accelerated since the end of 2024. Through June 2025, over 270,000 consumers had switched to independent household suppliers, of which over 250,000 are household. The following table presents data on the share of independent power producers and the IEC in the electricity market in 2023 and 2024, as published by the EA. December 31, 2023 December 31, 2024 Installed Capacity (MW) % of Total Installed Capacity in the Market Installed Capacity (MW) % of Total Installed Capacity in the Market IEC 10,527 44.4 % 8,834 36 % Independent power producers (without renewable energy) 7,302 30.8 % 8,901 36 % Renewable energy (independent power producers) 5,891 24.8 % 6,870 28 % Total in the market 23,721 100 % 24,605 100 % Energy generated (thousands of MWh) % of total energy produced in Israel Energy generated (thousands of MWh) % of total energy produced in Israel IEC 35,708 46.1 % 32,875 41 % Independent power producers (without renewable energy) 32,527 42.0 % 36,415 45 % Renewable energy (independent power producers) 9,141 11.8 % 11,097 14 % Total in the market 77,376 100 % 80,386 100 % 106 Set forth below are data regarding the distribution of consumers using private suppliers by voltage and number of consumers in mid-2025 (in %) (according to the EA’s data): Forecast of potential natural gas growth in the Israeli electricity market Long-term forecast (through 2040): On October 31, 2024, the Israeli government passed a resolution 2282 regarding “Promoting the Energy Security of the Israeli Electricity Sector”. The purpose of the resolution is to provide energy security in demand areas alongside the benefits of reducing air pollution and greenhouse gas emissions in accordance with the Israeli government’s objectives. Among other things, the resolution established the need to construct – by 2040 – conventional power plants in the geographical areas and years specified below Zones Need in 2031-2035 Need in 2036-2040 Zones 1-3 5 4 Zone 4 as well as the zone in Section 7(a)(1)(b)(2) to the Resolution 0 2 Zone 5 as well as the zone in Section 7(a)(1)(b)(3) to the Resolution 0 2 The resolution stipulates the scope of the approved plans required for securing a planning inventory; a total of 19 plans will be required, which will be zoned as detailed in the resolution, as well as conditions and criteria for promoting planning certification applications. According to the hearings and resolutions of the EA, by the end of the decade, at least four to five gas-powered conventional generation units are expected to be constructed (or alternatively reach financial closing) including the unit which is expected to be constructed under of the Sorek tender, with a capacity of up to 900 MW, the replaced unit in the Eshkol site with a capacity of up to 850 MW and up to four further conventional units, the construction of which is regulated under the EA’s resolution of March 2025, which revises the EA’s resolution of August 2024 and determines that, with a forward looking perspective beyond 2030, the quota will be increased such that the regulation will apply to up to 4 gas-fired combined cycle production units (with diesel fuel as backup), each with a capacity of no less than 630 MW and no more than 900 MW under ISO conditions, and which will receive tariff approval no later than June 30, 2027. The EA notes that it intends to discuss and make a decision regarding subsequent regulation through mid-2026 in order to provide regulatory certainty to developers, who wish to promote the construction of power plants. 107 Market Structure General In 2024, economy-wide production stood at approximately 80.4 TWh, of which approximately 70% were produced using natural gas. According to assessments outlined in the Electricity Sector Report, by 2030, the production mix is expected to change significantly: the production of facilities that generate renewable energy is expected to increase to approximately 28% of total production in the economy and to approximately 30% of total consumption in Israel. Coal-fired production is expected to be halted in accordance with the Minister of Energy’s policy, and the remaining capacity is expected to be generated using natural gas. In addition, in accordance with a draft for public comment of a comprehensive work published by the EA in January 2026, its recommendation to the Minister of Energy is to increase the renewable energy generation targets to 35% in 2035. Years prior to 2025 were characterized by a global trend of switching from electricity generation using fossil fuels and conventional technology to generation using renewable energy technologies. However, the generation of power and energy using conventional technology remains the main mode of production, and in the past two years this has been accompanied by forecasts of a substantial increase in demand for electricity, driven, among other things, by the rise in AI usage and the growing need for server farms, in addition to a global sentiment due to the change of U.S. administration, with the new administration supporting this trend and the government’s targets for gas-fired power plants. Government Resolution pertaining to the promotion of the construction of data centers On February 22, 2026, Government Resolution No. 3907 entitled Promoting the Construction of Advanced Data Centers to Strengthen Israel's Leadership in the Field of Artificial Intelligence was passed, whose aim is to accelerate growth in the field of artificial intelligence as a basis for economic-social growth and reinforcing Israel's global status in this regard, by encouraging the construction of advanced data centers in Israel for artificial intelligence uses. Under the resolution, the Government directs the Prime Minister (in the absence of a Minister of the Interior) to act to regulate the definition of data centers as a national infrastructure under the Planning and Construction Law, 1965, such that, subject to the conditions and criteria detailed in the resolution, plans for data centers will be promoted under the National Infrastructures Committee. Among other things, the certification criteria detailed in the resolution refer to electricity consumption capacity required for the data centers’ processing units, which must be at least 50 MW and is limited in certain areas to 200 MW; the criteria also refer to construction schedules, the existence of a means of electricity generation, etc. Furthermore, according to the resolution, no more than 10 data center plans will be submitted to the National Infrastructures Committee in a single calendar year. In a report published by the Ministry of Finance following interim recommendations of the inter-ministerial taskforce for the assessment of data centers’ energy requirements, under the energy sector’s support of the development of data centers in Israel. Data centers’ electricity consumption is high and that a sharp spike in grid connection applications at high capacities is expected to constitute a significant challenge for the electricity sector; in addition, in the long term, extensive execution of high-capacity grid connection applications may require the construction of 5-7 additional power plants and dozens of kilometers of transmission lines in addition to Israel’s expected needs through 2040, with environmental consequences and an impact on the utilization of natural gas reserves. After completing a series of measures aimed at increasing competition in the supply segment and fully opening it to competition - among other things by accelerating the rollout of smart meters and enabling consumers with basic meters to be assigned to virtual suppliers - the EA adopted resolutions intended to ensure an adequate response by the supply side both with regard to power generation - ensuring the supply of electricity generated through gas-fired facilities over the coming decade and deepening the incorporation of renewable energies and storage in the generation mix, and with regard to the supply of electricity to consumers, by increasing the supply of power generated by private producers, which virtual suppliers can purchase for their customers, and through a temporary mechanism for the purchase of capacity from the System Operator. Under the above actions, the EA has set a quota of 2,000 MW for renewable energy generation facilities co-located with energy storage, which were given the opportunity to enter into capacity transactions with virtual suppliers. The availability transaction will entitle the supplier to purchase energy at the half-hourly SMP at any hour, up to the available capacity the supplier had purchased from the producer. The producer will act in the energy market in accordance with the market-wide rules regarding the provision of capacity to the System Operator and the conduct required in the energy market. In addition, a Temporary Mechanism for Purchase of Capacity Certificates by Virtual Suppliers from the System Operator was set under which suppliers, which win a tender for up to 1,000 MW will be allowed to purchase capacity certificates from the System Operator until December 31, 2029. After the above date, the suppliers will be required to purchase capacity in the bilateral capacity market in accordance with the provisions of the regulation as they will be at that time. 108 Transmission Market Model Further to the IEC Reform and for the purpose of regulating the power plants sold by the IEC, the EA published Resolution No. 558 (“Resolution 558”) which regulated the activities of producers connected to the transmission grid and which have received tariff approval after March 1 2018, except for facilities using photovoltaic technology and wind turbines (including generation facilities to be sold by the IEC under the Reform) (the “Trade Rules”). Pursuant to the Trade Rules, producers were entitled to payments for capacity provided to the system operator (not attributed to a supplier or an onsite consumer) and for energy out of the facility’s available capacity, in accordance with the determined loading mechanism and the SMP (except with respect to producers for whom a tariff was set based on the recognized cost), subject to payments for deviations. In addition, detailed price mechanisms were set for compensation in respect of non loading and loading for which loss is incurred, and the producer is obliged to refrain from manipulations and from interfering with competition. As part of the resolution’s implementation, the EA established a wholesale energy market in which energy prices are set on a half-hour basis through economic loading of generation units by the system operator. Following Resolution 558, in February 2022, the EA further updated the regulatory framework relating to the transmission grid by passing the “Resolution on Applicability of the Market Model”. This resolution amends the regulation for producers in the transmission grid across all types of technologies and applies to them the covenants which regulate the operation of the energy market (the Trade Rules, as amended in the resolution). The amendments came into force in July 2024. The resolution establishes a uniform regulatory basis for generation facilities in the transmission grid in terms of the methods used for capacity payments, the manner of submitting generation and loading plans, and also for payments for energy; along with the creation of a uniform regulatory basis, the EA retains the ability of producers operating in bilateral transactions to continue operating in existing format, such that they are able to choose between a central loading method (selling energy to the grid in accordance with the system’s needs and at SMP, and purchasing energy from the system operator at SMP in order to sell it to consumers) and an individual loading method in order to protect the producers’ rights by virtue of the regulation under which they were established. As part of the Complementary Tariffs Resolution, the EA has reduced the applicability of the market model and stipulated that until such time when another resolution is passed, independent producers with variable capacity will only operate under individual loading. Pursuant to this resolution, the EA regulated producers’ activity in the transmission grid through various regulatory schemes that were limited in terms of their time and scope. Maximum tariff for complementary tariffs On February 17, 2025, the EA published a resolution to set maximum complementary tariffs for producers, which are connected to the transmission grid and operate under the market model (the “Complementary Tariffs Resolution”). As part of the resolution, the EA sets controlled protection tariffs paid to producers under the market regulation, such that a producer who is entitled to one of the two types of protection tariffs (complementary tariff or loading tariff outside the loading order) will receive a payment in accordance with the tariff cap set by the EA rather than in accordance with a proposal it will submit, if such a proposal is higher than the tariff cap set by the EA. According to the hearing, the protection tariff cap will be calculated based on the quarterly average gas price published by the Natural Gas Authority plus 40% for one-day advance netting or plus 60% for real time netting and the components of variable operation cost in accordance with the normative costs set in Regulation 914. Until further notice, with respect to producers operating with variable capacity as defined in the resolution, these producers will not be allowed to switch to central loading. Furthermore, these producers will be entitled to submit individual loading bids in accordance with the price cap set for them in the tariff approval or tender, and the proceeds for these bids will be according to the higher of the bid and the SMP (with regard to Rotem).OPC believes that, in view of its revenue structure, which is not materially affected by the SMP or by the complementary tariffs, the effect of the decision on OPC’s active projects is not expected to be material. 109 Resolution regarding Regulation of Conventional Units Further to a previous resolution and a hearing entitled Regulation for Conventional Generation Units, on March 26, 2025, the EA published a resolution entitled Revision to Resolution - Regulation for Conventional Generation Units. Under this resolution, the EA has set a quota for four conventional production units, with a capacity which does not fall below 630 MW and does not exceed 900 MW which will receive a tariff approval no later than June 30, 2027 and will provide evidence of financial closing based on this capacity in accordance with the requirements of their license. The capacity tariff which was set ranges from 3.05 agorot to 3.31 agorot, in accordance with the Financial Closing Date. In addition, incentives were put in place for the first producer to obtain tariff approval and complete financial closing on time under the regulation, provided that the power plant it constructs is located in the area defined in the hearing draft as Northern Gush Dan, and an additional incentive of 0.75% of the capacity tariff for each month of commercial operation to December 31, 2029. OPC pursuing the operation of the Hadera 2 Project (subject to its construction and compliance with the regulatory framework) under this regulation. The activity of producers, who started operating in the transmission grid prior to a Resolution on Applicability of the Market Model in the transmission grid is regulated mainly through various regulatory schemes, which have been capped in time and scope, including the following regulatory schemes, which are relevant to OPC’s operating environment: Regulation 241 Regulation 241 applies to sale of electricity under a fixed capacity track or under a variable capacity track and applies to conventional producers, whose commercial operation date was no later than the end of 2016. In general and subject to detailed terms, as stipulated, a private electricity producer established under Regulation 241 may sell electricity to private customers in a bilateral transaction and receive capacity payments for surplus energy not sold to private customers. Rotem, which operates under the tender it has won, is not subject to Regulation 241; however, this regulation only applies to some of its main competitors. Regulation 914 Under Regulation 914, it was determined that the generation units would be loaded into the grid in accordance with the economic load principle (“Regulation 914”) and a higher capacity tariff was set for generation facilities that meet the flexibility requirements. In addition, the resolution offers open-cycle (“peaker”) producers several gas supply alternatives. According to the resolution, entering into bilateral transactions for open cycle facilities was restricted, and, on the other hand, combined cycle facilities are required to sell at least 15% of their production capacity to private consumers. Zomet operates in accordance with Regulation 914. Regulatory Framework for Cogeneration IPPs According to the resolution made by the EA, electricity producers using cogeneration technology may sell electricity to private customers as well as electricity surplus (i.e., electricity generated by a power plant but not sold to private customers) to the System Operator at the tariff stipulated in the tariff approval granted to the producer. To benefit from the fixed arrangements for cogeneration electricity producers, each generation unit in a power plant must meet the minimum energy utilization conditions set forth in the Cogeneration Regulations, and if it does not meet them, a less favorable tariff arrangement will apply. According to the regulations, cogeneration producer may elect whether to sell to the System Operator during on-peak and mid-peak hours, up to 70% of the electricity generated for a period of 12 years from the issue date of the permanent license or 50% of the electricity generated for a period of 18 years from the issuance date of the permanent license. During off-peak hours, the cogeneration producer may sell up to 35 MW to the System Operator, provided it is a unit with an installed capacity of less than 175 MW calculated annually. Hadera is a cogeneration producer and is subject to the terms and conditions of the regulations (as described below). 110 In accordance with the Cogeneration Regulations, the EA established an arrangement for electricity producers that no longer meet the conditions required for a cogeneration facility (a “hedged capacity transaction”). Such arrangement applies to the Gat Power Plant pursuant to conditions set in the approval of the tariff. The Cogeneration Regulations were designed to encourage and incentivize the establishment and operation of cogeneration facilities, while maintaining the efficiency provided for in the Regulations and maintaining the advantages afforded by cogeneration. The Cogeneration Regulations establish threshold requirements for compliance with the cogeneration facility conditions, and they regulate, inter alia, the mechanism for making transactions between the System Operator and a cogeneration independent producer. According to the Regulations, a cogeneration independent producer may choose to enter into a purchase transaction with the System Operator, who will be obligated to purchase energy from the producer in accordance with the Regulations. Furthermore, pursuant to the Regulations, there is an option of executing a bilateral transaction between a cogeneration facility and the various electricity consumers in the economy. The minimum annual energy efficiency requirement for the cogeneration generation units at the Hadera Power Plant is 60%. Regulatory Scheme for High Voltage Producers Established without a Tender. In March 2019, the EA published a resolution on the subject of “Regulatory Scheme for High Voltage Producers Established without a Tender”; this scheme, stipulated within a 500 MW quota, permits generation facilities to be constructed in the consumers’ premises, and half of which is intended for generation units to be established in desalination facilities. Such facilities will be permitted to supply the electricity generated by them directly to the onsite consumer and to transfer any surplus to the electrical grid – all in accordance with the Trade Rules. The Sorek 2 Power Plant is expected to operate by virtue of this regulation, subject to the completion of its construction (“Regulation 555”). Regulation 555 was extended several times; under the latest extension, its term was extended through July 1, 2025 with a reduction in the capacity tariff in accordance with milestones set. Resolution entitled Bilateral Market Regulation for Generation and Storage Facilities Connected to or Integrated into the Transmission Grid. Further to a previous hearing entitled “Bilateral Market Regulation for Generation and Storage Facilities Connected to or Integrated into the Transmission Grid,” in May 2025, the EA published a resolution entitled Bilateral Market Regulation for Generation and Storage Facilities Connected to or Integrated into the Transmission Grid. The regulatory scheme will apply from January 1, 2026 to renewable energy production facilities co-located with storage (it has been determined that the facility will be required to meet a storage capacity ratio for installed production capacity of up to 7) which will receive tariff approval by June 1, 2027 or up to a cap of 2,000 MW. In accordance with the resolution, renewable energy generation facilities, including those co-located with storage, were allowed to enter into capacity transactions with virtual suppliers. The availability transaction shall entitle the supplier to buy energy at the half-hourly SMP at any hour, up to the total availability certificate the supplier purchased from the producer. The power specified in the capacity certificate will be determined in accordance with the capacity credit. The capacity credit for a renewable energy facilities co-located with storage of 4 or 5 hours of offloading, which will receive tariff approval under the initial quota of the regulation, will be at a rate of 60% and 67%, respectively, through 2036. Such a storage facility will operate in the energy market using the central loading method. A producer, except for an independent storage producer, which will not allocate to suppliers all the capacity specified in its capacity certificate, may request from the System Operator a capacity tariff of 1.75 agorot divided by the capacity credit set for the facility - non-linked - with respect to the capacity not allocated to a supplier, provided that the producer will not be able to allocate this capacity tariff to an independent supplier for 12 months. The Ramat Bekka Project, which is under advanced development stages, is expected to operate under this regulation (subject to a place within the quota, obtaining the appropriate tariff approval, completing the construction of the facility and operating it). Under the resolution, the EA also set a quota for independent storage facilities and waste energy reclamation facilities. The EA notes that as it extends to conventional generation units, the regulatory scheme will replace Regulation 555 (as discussed below), which comprises the regulatory framework for consumer-sited generation facilities. 111 Regulation for facilities connected to the distribution grid generating electricity using natural gas In November 2018, the EA issued a resolution on the “Regulation of the Activities of Natural Gas Generation Facilities Connected to the Distribution Grid,” following which it published a tender to set and allocate the capacity tariff for these facilities. The arrangement is designed to allow producers with a capacity lower than 16 MW to construct a power plant on a consumer’s premises and provide them with the electricity generated on its premises. Market model for generation and storage facilities connected to or integrated into the distribution grid In September 2022, the EA published a resolution on “market model for generation and storage facilities connected to or integrated into the distribution grid” (the “Market Model”) The resolution regulates the generation activity (using all different technologies) and storage facilities in the distribution grid, and determines their option to sell electricity directly to virtual suppliers as from January 2024. Producers connected to the distribution grid may also sell to consumers (through virtual suppliers) as part of the market distribution model. OPC expects that, in the short term, the resolution reduces the economic viability of the virtual supply activity, and in the long term, the resolution encourages increased competition in the supply segment while integrating generation facilities and storage facilities. Virtual supply (activity for suppliers which do not have means of generation) and the resolution entitled Temporary Mechanism for Purchase of Capacity Certificates by Virtual Suppliers from the System Operator In February 2021, the EA established for the first time a regulatory scheme for suppliers with no means of generation for the first time (“Virtual Supply”), including criteria and tariffs to purchase energy for their consumers at the tariffs to be based on an SMP-based component and components affected, inter alia, by the scope of consumption during peak demand. In June 2024, the market opened to household consumers having a basic meter, who could engage with a virtual supplier starting from September 2024, and with conventional suppliers – starting from January 2025. In July 2021, OPC was awarded a virtual supply license and entered into virtual supply agreements with customers. OPC acts as the virtual supplier of consumers in accordance with virtual supply agreements or additional supply agreements. In April 2024, the EA amended and revised the criteria in a manner that enables the integration of basic meters into supply-side competition, allowing household consumers without a smart meter to be assigned to private transactions based on a normative consumption model of a household consumer. The resolution allows OPC to further diversify its customer base by selling electricity - directly and/or indirectly - to all households. In November 2025, the EA passed a resolution entitled “Temporary Mechanism for the Purchase of Capacity Certificates by Virtual Suppliers Directly from the System Operator No Later than December 31, 2029”, in order to increase the competitive capacity available to the suppliers until full regulation of competition in the supply market. Further to the resolution, a tender was announced in 2025, and another tender will be announced during 2026. The winning bidders in the tender will be able to purchase capacity certificates from the System Operator at the tariff set in the winning bid through December 31, 2029. OPC believes that the measures taken by the EA to open up the supply segment to competition and extend the supply for suppliers have increased the number of entities operating in the household supply segment and the scope of consumption associated with independent suppliers in a manner that is expected to boost the growing competition in this segment. Given current regulatory restrictions on electricity supply through virtual suppliers from current conventional bilateral generation facilities, electricity supply to household consumers transactions are made through contracts between conventional bilateral suppliers and business entities operating in the retail sector, such as telecommunications and gas providers holding virtual supply licenses and serving, for the purposes of the transaction, as a type of subcontractors for the conventional suppliers for the purpose of marketing and providing the service to household consumers. Overview of United States Electricity Generation Industry The electricity market in the United States, in which CPV operates, is the largest private electricity market in the world with installed capacity of approximately 1,300 gigawatts of generation facilities. The generation mix has changed significantly over the last several years. In 2016, natural gas overtook coal as the primary fuel source for electricity production in the United States, after coal comprised over 50% of the electricity supply since the 1980s. These changes have been driven by federal and state environmental policies, as well as the relative cost of the fuel sources and the advancement in technologies. These factors also have greatly contributed to the growth in renewable technologies over the last several years. Alongside the increasing demand for renewable energy, environmental goals of large commercial and industrial customers are driving demand for renewable energy. 112 The wholesale electric marketplace in the United States operates within the framework of several FERC-approved regional or state market operators, including RTO or ISO. RTO/ISOs are responsible for the day-to-day operation of the transmission system, the administration of the wholesale markets in the regions in which they operate, and for the long-term transmission planning and resource adequacy functions. In most cases the ISO’s and RTO’s powers are concentrated under a single entity. The RTOs and ISOs are regulated by FERC, except for ERCOT (the Texas electricity market in which CPV Basin Ranch project will operate subject to completion of construction), which is regulated by the Public Utility Commission of Texas, which in turn is subject to laws enacted by the Texas state legislature. In addition to FERC, at the wholesale level, states regulate the sale and distribution of electricity, within each state, and the RTOs/ISOs, which are the key players in the wholesale electricity markets in the United States, in which CPV Group operates, include other electricity producers and local utility companies, that serve both wholesale and retail customers. Many of the other electricity producers (especially producers that joined recently), and local electricity companies operating in these wholesale markets, are privately owned entities; however, those market players include a number of publicly owned cooperatives, municipal utility companies, state power authorities and several federal regional power administrations established by the U.S. Congress. Each of the ISOs and RTOs operates energy markets and related services with buyers and sellers submitting bids and offers to sell or supply electricity and related services, including energy, operating reserves, regulation service, etc. Some of the ISOs and RTOs also operate capacity markets. ISOs and RTOs operating in competitive markets use a demand-based electricity selling system, and a marginal price set by electricity producers to meet the regional consumption needs. In large parts of the United States, including the Southeast, Southwest and Northwest regions, the electricity management system has a more traditional structure where the local electric utility company is in charge of load management and the production mix. In these traditional markets wholesale physical power trade typical occurs through bilateral transactions. CPV Group operates mainly in competitive markets managed by ISOs or RTOs. Capacity is a payment made to generators and other suppliers designed to ensure that there are sufficient generating and supply resources to ensure the RTO can meet its reliability standard. The capacity markets typically pay electricity generators to participate in the energy market and for their ability to generate energy at the required times for purposes. This payment component is an additional component separate and apart from the component based on the energy prices (which is paid in respect of sale of the electricity). Definition of the payment component, as stated, including entitlement to a payment for seeing to availability of the electricity, including provisions regarding bonus or penalty payments, are (except with respect to ERCOT, which is not FERC-jurisdictional and as noted below does not have a capacity market) governed by the tariffs approved by the FERC. Accordingly, NYISO, PJM and ISO NE operate capacity auctions to determine the capacity price. The impact of the capacity payments on the overall results of CPV Group changes as a function of the capacity prices from these auctions. NYISO, PJM and ISO-NE publish clearing prices from capacity auctions. In the markets in which CPV operates, an increase in the capacity prices favorably impacts CPV Group’s results, and vice versa. In addition to revenues from the sale of energy, related services and capacity, until certain changes imposed by Trump Administration since 2024 as described below, generators of renewable energy and of low-carbon energies benefited from government mechanisms and incentives. Both U.S. federal and state governments offer incentives to suppliers to meet the state specified renewable energy targets. A number of states require the local electric utility company to acquire a certain quantity of RECs in accordance with the total consumption of their consumers. In addition, there are federal tax incentives in connection with production of and investment in renewable energy technologies and other low-carbon technologies, which also constituted a financial incentive to develop specific production technologies. Furthermore, each state has in place environmental protection regulations, which may provide incentives and encourage the closure of existing production facilities that use fossil fuels. As a result of the change in the federal administration following the 2024 presidential elections, the scope of such benefits as described above was reduced or changed mainly with respect to renewable energy, under the One Big Beautiful Bill Act (the “OBBBA”) enacted in 2025 and other changes in the policy of the new administration of President Trump. While each of the ISOs and RTOs has the same function on the federal level, there are significant regional differences between markets in terms of their government and market structure; those differences may affect the execution and the economic feasibility of new projects, and promote or delay investments in new projects. CPV Group operates mainly in advanced markets managed by ISOs or RTOs. 113 Operating Structure in various markets The electricity market in the United States has both Federal oversight (wholesale sales of electricity and inter-state transmission) and State oversight (retail sales of electricity and provision of distribution service to end users). The major players in the U.S. electricity sector are RTO, FERC, and ISO, electricity producers (which are, in general, private entities) and electric utility companies and electricity distribution companies operating on behalf of the different consumers (such as private and commercial consumers). The primary federal regulator is the Federal Energy Regulatory Commission (FERC), alongside separate state-level Public Service Commission’s exercising oversight in their respective states. The wholesale electric marketplace in the United States operates within the framework of several FERC-approved regional or state market operators, including RTO or ISO. RTO/ISOs are responsible for the day-to-day operation of the transmission system, the administration of the wholesale markets in the regions in which they operate, and for the long-term transmission planning and resource adequacy functions. The PJM Market The PJM Interconnection (PJM) is an RTO and ISO that operates a wholesale electricity market and serves as an administrator of the electric transmission system which covers parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia, serving more than 67 million residents. The PJM Market is the largest among the RTOs with approximately 177 gigawatts of installed capacity and peak demand of approximately 160 gigawatts in 2025 and its internal forecasts indicate a peak demand of approximately 156 GW for 2026. PJM oversees the operation of more than 150,000 kilometers of transmission lines. Sale of electricity in the organized PJM Market is supervised and managed by PJM to assure supply of the electricity, based on price offers of the electricity generators. The PJM is regulated by the FERC and operates the PJM Market and transmission system pursuant to a FERC-approved tariff; and is financed by payments from participants in the market. PJM collects payments for capacity, electricity, transmission, accompanying services and other services required for operation of the electricity system from utilities and electric distribution companies acting on behalf of consumers (households, commerce and industry), and distributes the payments to the generators and transmitters, by means of a variety of market mechanisms, including purchase of capacity (Forward Capacity Market) and the purchase of electricity in the Day-Ahead and Real-Time markets. In general, the capacity price is determined in an annual auction for a delivery year three years in advance and is guaranteed without reference to the actual amount of electricity generated. For the supply year starting 2023/2024, the capacity auction on the PJM was postponed due to FERC’s procedure for assessing the fairness and reasonableness of the methodology and inputs used to determine the auction prices in PJM’s reserves capacity tender. The capacity auctions for 2023/2024 took place in June 2022; they are expected to be held every six months until the normal timelines for three-year forward tenders is renewed. Payments for electricity are made for actual electricity generation and are determined on the basis of the marginal price in the market. In July 2024, the capacity auction results in PJM were published, with a significant increase in the prices to approximately $270 per megawatt per day for the 2025/2026 period. The 2026/2027 capacity auction was held in July 2025. The 2027/2028 capacity auction was held in December 2025. In September 2024, complaints were filed with the FERC in order to make certain changes in the upcoming capacity auctions in the PJM Market. In response, PJM proposed an up to six-month postponement of the auction that was originally scheduled for December 2024 in order to make changes, including, among others, inclusion of about 2 GW of RMR (Reliability Must Run units) as part of the offer. In addition, PJM is considering an update of the manner of determining the demand curve. CPV believes that if such changes in capacity auctions are accepted and approved by the FERC, the fluctuations in the capacity tariffs should be moderated. In February 2025, FERC approved PJM’s proposed modifications to the capacity market framework which were intended to reduce the volatility of pricing between the auctions. The revisions include (i) the continued use of the gas turbine as the index for the demand curve, (ii) the inclusion of Reliability Must Run units—resources scheduled to retire that are retained for reliability purposes—into the capacity market auctions as generic supply, (iii) setting of a uniform penalty rate for under-performance across all generation resources, (iv) increased flexibility in offer submissions and (vi) elimination of the automatic must-offer exemptions for certain resource classes. In April 2025, FERC approved a PJM proposal to establish upper and lower price collars of $329/MW-day and $177/MW-day, respectively, for the next two capacity auctions, subject to minor adjustments. In July 2025, PJM published the results of capacity price auctions for the period June 2026 and up to May 2027 where the price was determined based on the maximum price of $329.17/MW-day, which reflects an increase of about 22% compared with the capacity price in the prior auction for the 2025/2026 period. In addition, the capacity rating for the power plants was updated, resulting in a reduction in the available capacity provided for sale by the class of CPV Group’s natural gas-fired power plants – from approximately 79% to around 74%. PJM recalculates these ratings annually for each asset class to measure how much a resource supports grid reliability during peak and extreme conditions, which determines the percentage of its capacity eligible for auction revenue. These ratings may shift from year to year due to updates to PJM’s load forecasts, weather and outage assumptions and available resources. 114 In December 2025, PJM published the results of capacity price auctions for the period June 2027 and up to May 2028 where the price was determined based on the maximum price of $333.44/MW-day, which reflects the cap that was set under the above PJM collar decision. According to PJM’s publications, the theoretical price derived from the results of the auction, with no maximum collar, which as stated was set in the auction, would have been $529.8/MW-day. The available capacity provided for sale by CPV Group’s natural gas-fired power plants remained at 74% consistent with the prior auction for the 2026/2027 period. The 2027/2028 Base Residual Capacity Auction (BRA) underscored the continuing trend of fast rising demand attributed to large data center load additions coupled with a shortage of supply entering the market due to slower build timelines and interconnection delays. PJM disclosed that the results of the 2027/2028 Base Residual Auction (BRA) cleared 5.6% (about 6,500 MW) short of PJM’s target reserve margin, indicating the system is at higher risk than prior years. The 2026 Load Forecast published by PJM in January 2026 continued to show load growth over the planning horizon, albeit at a slightly slower initial pace than forecasted in the 2025 Load Forecast. In January 2026, The National Energy Dominance Council, an advisory body within The White House, along with a group of State Governors, issued a statement of principles urging PJM to expeditiously file for tariff changes at the FERC, to address the following: i. Implement a Reliability Backstop Auction for the 2027/2028 planning year wherein the cost of any incremental capacity acquired be allocated to data centers that have not self-provided generation or agreed for their load to be curtailable, ii. Extend existing price collars to the next two capacity auctions (2028/2029 and 2029/2030 planning years), iii. Embark on a stakeholder process to reform capacity markets, iv. Improve load forecasting to ensure large loads are verified, v. Accelerate ongoing generator interconnection studies. The National Energy Dominance Council does not have independent regulatory authority over PJM or FERC-jurisdictional tariffs and while it may recommend actions to PJM it cannot direct PJM or FERC to embark on market reforms. Based on public releases, in January, 2026, PJM’s Board took the recent capacity auction outcome as a clear signal that current trends within the market warrant corrective action to ensure that the region’s supply/demand balance and reserve margins are restored to a level that ensures reliability for existing customers and new large load additions to the market. PJM’s Board issued a letter to stakeholders on January 16, 2026 regarding the Critical Issue Fast Path (“CIFP”) accelerated stakeholder process for large load additions. The PJM Board directed PJM Staff to implement, subject to FERC approval as applicable, the below transitional measures while the industry and the government work collectively to bring more supply to the system to meet unprecedented growth in demand (the “CIFP Outline”): i. Implement load forecasting improvements to refine projections for the 2027 forecast, including state and 3rd party review of large load additions. ii. Pursue a Voluntary Bring Your Own New Generation (BYONG) and Expedited Interconnection Track wherein large loads bring their own incremental generation to the system to offset their requirements and provide for an alternative expedited path to be in place by August 2026. The expedited timing would allow certain shovel-ready resources to execute generation interconnection agreements (GIAs) and provide for a faster path to construction and network upgrade certainty. 115 iii. Implement Connect and Manage (demand response) process for the 2027/2028 capacity year by year end 2026 for large load customers. iv. Immediate initiation of Reliability Backstop Procurement to procure additional capacity to meet reliability requirements and ensure resource adequacy is met for the 2027/2028 capacity year. v. Perform a comprehensive review of investment incentives in PJM Market in the first half of 2026 to assess whether market design is appropriate to attract timely new supply to enter the market. vi. Request for written stakeholder comment regarding whether the administrative price collars in place for the 2026/2027 and 2027/2028 auctions should be extended for 2 additional auctions to 2028/2029 and 2029/2030. On February 27, 2026, the PJM Board made a filing, subject to FERC approval, to extend the administrative price collar to 2028/2029 and 2029/2030 capacity auctions. The remaining steps are under review and consideration, including with respect to potential future capacity years under (iv) above. CPV Group is acting to advocate for its Low Carbon Projects to qualify for the Reliability Backstop Procurement, however, there is no certainty as to the outcome of the above initiatives, their terms or if the timeline will be adopted as planned. Therefore, at this stage there is no certainty as to the implications of the above initiatives on the capacity auctions in the long term or CPV Group’s Low Carbon Projects. Two capacity auctions for the period from June 1, 2026 through May 31, 2028 were published at a price of about $330 for megawatts/day, which reflects the ceiling for the price range that was approved by the FERC. In February 2026, PJM submitted a request to FERC for approval of extension of the maximum and minimum limits (collar) for two additional capacity auctions from June 1, 2028 through May 31, 2030, which has not yet been approved. At the same time, in the PJM regulatory processes are being considered with the goal of assuring a balance between supply and demand and maintaining reliability of the electricity grid, in light of the new significant additional energy demand expected to enter the market, particularly existence of emergency capacity auctions (Reliability Backstop Auctions) up to September 2026 that will include capacity prices for a period of up to 15 years. Interconnection Procedure The increasing demand for renewable energy in recent years across the U.S., led to an increase in demand for connections to the grid and requests for connection surveys of projects to the grid. These demands cause overload and delays in processes for approving the connection, and may affect the procedure and pace of advancing development projects. The PJM Interconnection Reform which was designed to regulate the process of addressing the large backlog of interconnection applications by PJM, was approved by the FERC (subject to conditions), and entered into effect in January 2023. Under the current protocol, PJM holds a comprehensive, three-phased interconnection analysis procedure that applies to all applicants who have filed an interconnection application within the relevant time frame. At the end of the three phases, there is a period during which entities are able to engage in interconnect agreements. However, projects that do not need grid upgrades are allowed to progress to the interconnect agreement phase after the first two stages. CPV has indicated its view that the outcomes of interconnection analysis have caused a longer period (approximately 2-3 years) or delays in the development of certain projects in the PJM Market and additional costs as may be required because of grid upgrades, which also may affect the interconnection process timeline. The Maple Hill and Three Rivers projects are not expected to be impacted by the reform. In February 2025, FERC approved PJM’s Reliability Resource Initiative (RRI) which aims to address anticipated capacity shortfalls by accelerating the interconnection of up to 50 generating projects that meet certain criteria. Qualifying projects will be advanced into the next interconnection cycle, Transition Cycle #2. During 2025, CPV submitted an application (including required collateral) for its Oregon Low Carbon Project (currently a project under development) to be included under this accelerated interconnection process. Taking into account the interim results of the interconnection studies received during Q4 of 2025, currently, CPV Group did not advance the Oregon Project in the framework of an accelerated interconnection process. CPV Group is continuing to examine various alternatives for advancement of the development project and there is no certainty as to their outcome at this stage. 116 The NYISO market The NYISO market has operated since 1999, and is one of the most advanced electricity markets in the United States and in the world. The NYISO market includes about 38 gigawatts of generating capacity and more than 18,000 kilometers of transmission lines, serving about 20 million residents with a peak demand forecast of approximately 32 gigawatts for 2026. The market is divided into 11 pricing regions (zones). The pricing of the electricity and capacity varies among the regions due to transmission constraints between the regions and the available demand and available supply. The NYISO electricity market includes a Day-Ahead and Real-Time market for the sale of electricity and other ancillary services. In addition, the NYISO has operated a capacity market since 2003 with capacity prices set through monthly spot auctions, and the ability to sell capacity forward across two six month seasonal auctions. Capacity payments are independent of the amount of electricity generated, although taking on a capacity obligation requires a resource to participate in the daily energy market. Similar to the PJM Market, the NYISO market capacity payments are made as part of a mechanism for centralized purchase of capacity. The electricity prices are determined on the basis of the marginal price on the market. NYISO holds seasonal auctions every spring for the coming summer (May to October), and in the fall for the coming winter (November to April). In addition, monthly supplementary auctions are held for the unsold capacity in the seasonal auctions. The power plants are permitted to guarantee the capacity tariffs in the seasonal and monthly auctions or through bilateral sales. Below are the capacity prices set in the seasonal auctions held in the NYISO market. The capacity prices rose compared with prior periods due to exit from the system of power plants and an anticipated increase in demand (prices are denominated in USD for megawatt per month). Sub-zone CPV power plants Winter 2025/2026 Summer 2025 Winter 2024/2025 Summer 2024 NYISO Rest of the Market — 89.83 153.26 66.30 168.91 Lower Hudson Valley Valley 89.83 153.26 66.30 168.91 Source: NYISO - Converted from dollars for kilowatt per month to dollars for megawatt per day. The Valley power plant is located in Area G (Lower Hudson Valley) and the actual capacity prices for the Valley power plants are impacted by the seasonal auctions, the monthly auctions and the SPOT prices, with variable capacity prices every month, as well as bilateral agreements with energy suppliers in the market. The ISO–NE market ISO–NE is the ISO responsible for managing the day-to-day operation of the New England transmission system, as well as administering the wholesale electricity and capacity markets in New England. ISO–NE was created in 1997 to operate the wholesale power market under the direction of the New England Power Pool (NEPOOL). In 2005, ISO-NE became an independent RTO. NEPOOL became the exclusive stakeholder advisory organization to ISO-NE. ISO-NE has authority over the day-to-day operation of the power system, market administration, transmission planning and resources adequacy. The ISO-NE managed footprint covers Connecticut, Massachusetts, New Hampshire, Rhode Island, Vermont, and most of Maine. It serves about 15 million residents with a generation scope of about 29 gigawatts and peak demand of about 27 gigawatts in summer 2025. ISO-NE administers more than 9,000 kilometers of transmission lines ranging from 115kv to 345kv and including 13 transmission interconnections to neighboring control areas NY, Quebec, and New Brunswick. ISO–NE is a non-profit FERC-regulated entity which operates pursuant to a tariff on file with FERC. Similar to the PJM Market, in the ISO NE market capacity payments are made as part of a central mechanism for acquisition of capacity. In the ISO NE market, there are a number of submarkets, in which capacity requirements differ as a function of local supply and demand and transport capacity. ISO NE executes forward auctions for a period of one year, commencing from June 1, three years from the year of the tender. In addition, there are supplementary monthly and annual auctions for the balance of the capacity not sold in the forward auctions. The Towantic power plant is located in the Mass Hub sub-market. The power plants are permitted to guarantee the capacity payments in the forward auctions, the supplementary auctions or through bilateral sales. Set forth below are the capacity payments determined in the sub regions that are relevant to the Towantic power plant (the prices are denominated in dollars per megawatt per day): Sub-area CPV power plants 2027/2028 2026/2027 2025/2026 ISO-NE Rest of the market Towantic 117.70 85.15 85.15 The actual capacity payments for the Towantic power plant are impacted by forward auctions, supplemental annual auctions, monthly auctions with variable capacity prices in every month and bilateral agreements with the energy suppliers in the market. The ISO NE market is in the midst of a comprehensive reform process with respect to the structure of the capacity market The markets in New England includes a Day-Ahead and Real-Time Energy Market for the sale of electricity, a Day-Ahead co-optimized reserve market, and a Forward Capacity Market with auction that run three years in advance of the delivery period. Since the last capacity auction was held in February 2024 for the 2027-2028 delivery period (FCA 18), ISO-NE has received approval from FERC to suspend subsequent auctions as it redesigns its capacity market into a prompt auction, the first of which will be held in May 2028 for a June 2028/May 2029 delivery period. In December 2025, ISO-NE and NEPOOL filed with the FERC a proposal to permanently change its Forward Capacity Market design to a prompt auction design going forward. ISO-NE has announced plans to file further changes to its auction design to shift from an annual auction, to two six-month seasonal auctions, similar to NYISO’s strip auction design. Both components of this new design are expected to be implemented, subject to FERC approval, for the next capacity auction which will be expected to run in May 2028, for the capacity supply period between June 2028 and May 2029. ERCOT CPV Group’s Basin Ranch project (which commenced construction stage in the fourth quarter of 2025) is expected to operate in the ERCOT market subject to and upon completion. ERCOT manages the flow of electrical power to more than 27 million customers in the state of Texas, representing approximately 90% of Texas’ electrical load. ERCOT schedules power on an electric grid that connects more than 54,100 miles of transmission lines and 1,250 generation units, including private use networks. ERCOT operates as an energy-only market with real-time, Day-Ahead, and ancillary service markets, and also performs financial settlement for the competitive wholesale bulk-power market and administers retail switching for 8 million premises in competitive choice areas. ERCOT is governed by a board of directors, subject to oversight from the Public Utility Commission of Texas and the Texas legislature, its members include consumers, cooperatives, generators, power marketers, retail electric providers, investor-owned electric utilities (transmission and distribution providers) and municipal-owned electric utilities. 117 ERCOT operates as an independent system operator (ISO) and is responsible for the reliability of the electricity grid and operation of the competitive wholesale electricity market. ERCOT operates solely within the borders of Texas, under local Texas regulation (PUCT), and is not subject to the Federal Energy Regulatory Commission (FERC) oversight. In general, ERCOT operates independently from electricity transmission systems in west and east Texas. ERCOT has a competitive wholesale electricity market, which includes a Day-Ahead market and a Real-Time market for sale of electricity and ancillary services. ERCOT does not operate a capacity market, in contrast with the markets in PJM, NYISO and ISO NE, instead relying on the higher volatility in energy prices to incent new resources where and when needed on the grid to maintain reliability. There has been significant growth and continuing demand in the ERCOT electricity market due to, among other things, a rapid increase in the population of Texas, expansion of the industrial activities, an increase in the demand for electricity from energy intensive segments, such as, data centers, crypto miners, as well as significant efforts to electrify the oil and gas infrastructure primarily in the Permian Basis area in and around the location of Basin Ranch. In recent years, the peak summer demand for electricity in the ERCOT system reached over 83 GW in 2025. Based on the forecasts published by ERCOT, the summer peak is projected to reach 126 GW by 2031, reflecting an average annual growth rate of 13.6% in the demand for energy from 2026 to 2030. Basin Ranch is expected to be exposed to risks relating to the energy prices and market conditions, similar to projects in other RTOs and to mitigate such risks it is expected to enter into hedging agreements. Regulatory, Environmental and Compliance Matters Israel Electricity Sector Rules The Electricity Sector Rules, including the Electricity Sector Rules (Transactions with an Essential Service Provider), 2000 (the “2000 Rules”) and Electricity Sector Rules (Transactions with an Essential Service Provider), 2020 (the “2020 Rules”) - which are applicable as from June 28, 2020 to producers in the transmission grid, regardless of the technology used, who obtained a tariff approval after March 1, 2018 - are designed to regulate the engagement of independent power producers in transactions with the System Operator and set out the principles for such transactions. Covenants The covenants are set by the EA and regulate the level, quality, and nature of the service provided by the license holder to the essential service provider. The covenants are updated from time to time and are published in the Official Gazette as a condition for their entering into effect. The main covenants that affect the Group’s activities are, among others: Covenants entitled Private Transactions (Chapter E of the Covenant Code) The covenants in Chapter E, entitled Private Transactions, govern the supplier’s ability to execute private transactions with consumers, and stipulate, among other things, the supplier’s obligations, (such as provision of a collateral), and the process of assigning producers to suppliers, and consumers’ switching suppliers. In addition, as part of these covenants, rules and payment mechanisms are stipulated in respect of deviations from the consumption plan. Covenants entitled Purchasing Electricity, Maintenance, and the Operating Regime for Independent Production License Holders (Chapter F of the Covenant Code) The covenants in Chapter F regulate the rules for the conduct and netting of independent power producers using various technologies with the System Operator. 118 Covenants entitled Connecting Generation Facilities to the Electrical Grid The covenants set in Chapter C, Item C and Item D to the Covenant Code stipulate the commercial mechanism for connecting generation facilities to the distribution grid and to the transmission grid, including the mechanisms for ensuring the ability to transfer energy from the facility to the electrical grid, subject to compliance with various conditions, such as non-concentration approval, which are specified therein. Pursuant to deviations from the consumption plans, Resolution No. 573 regarding deviation from the consumption plan (“Resolution on Deviations from Consumption Plans”), an electricity supplier related to a bilateral producer may not sell more to its consumers than the total capacity that is the object of all the engagements it has entered into with independent generation license holders. Actual energy consumption at a rate higher than 3% of the installed capacity allocated to the supplier will trigger payment of an annual tariff reflecting the annual cost of the capacity the supplier used as a result of the deviation, as detailed in the resolution ( “Annual Payment Due to Deviation from the Capacity”). In addition, the resolution stipulates a settlement of accounts mechanism due to a deviation from the daily consumption plan (surpluses and deficiencies), that will apply beside the Annual Payment Due to a Deviation from the Capacity. The resolution applies to Hadera, Gat and Rotem. On March 13, 2024, the EA resolution was delivered, which came into effect on July 1, 2024, under which covenants were applied to Rotem, including, among other things, by virtue of the resolution regarding deviations from consumption plans. Covenant 125 – use of alternative fuel Covenant 125 regarding the use of alternative fuel establishes rules regarding the use of alternative fuel, including with regard to the obligation to hold and supplement the diesel fuel inventory held at the site and the transition to production using diesel fuel in the event of shortage of natural gas used for electricity generation, in the electricity sector. In addition, OPC uses natural gas to generate electricity and also enters into agreements regarding the sale and purchase of natural gas as an ancillary action to the generation activity, and therefore, the regulatory arrangements in the natural gas sector, including the Natural Gas Sector Law and regulations thereunder, and decisions of the Ministry of Energy and of the Gas Authority have an indirect impact on OPC’s operations in Israel. Rotem, Zomet, Hadera and Gat serve as members of the Forum of Power Producers Using Natural Gas and Hydrogen as well the Green Energy Association of Israel, which promote regulatory issues faced by independent power producers in the electricity sector in Israel, including regulators, legislators and the public. The organizations’ activities are financed by the members. Environmental Regulations Operations in the electricity sector naturally entail the risk of causing environmental harm, which may arise, inter alia, from electricity production, malfunctions or unexpected events. Environmental laws applicable to OPC’s business include the Prevention of Hazards Regulations (Used Oil), 1993; the Planning and Construction Law, 1965; the Licensing of Businesses Law, 1968; the Water Regulations (Prevention of Water Pollution) (Gasoline Stations), 1997; the Hazardous Substances Law, 1993 (the “Hazardous Substances Law”); the Clean Air Law, 2008 (the “Clean Air Law”); the Non-Ionizing Radiation Law, 2006; the Environmental Protection Law (Environmental Emissions and Transfers - Reporting and Register Requirement), 2012; the Collection and Disposal of Waste for Recycling Law, 1993; the Licensing of Businesses Regulations (Hazardous Enterprises), 1993; the Transport Services Regulations, 2001; Regulations for the Prevention of Hazards (Unreasonable Noise), 1990; and various other bylaws and procedures. In order to ensure compliance with the environmental regulations in its operating activities, OPC has formulated an internal compliance program in the field of environmental risk management through external consultants specializing in environmental issues. The internal compliance program and internal audits carried out by OPC cover a range of issues, including emissions, handling and storing hazardous substances, soil and water contamination, and more. The policy sets criteria for the measurement of each of the above aspects, alongside principles for reporting and taking remedial actions. The audit findings are reported to the facility site manager and forwarded to the relevant parties in OPC and to the steering committee established with regard to this topic. 119 OPC also has in place a risk management plan designed to allow OPC to monitor and report various risks and to appoint parties to be in charge of addressing with them. Under OPC’s environmental risk management policy, Rotem, Hadera, the Hadera Energy Center and Zomet have implemented an internal environmental enforcement plan, with the aim of ensuring the companies’ compliance with environmental requirements, including air pollutant emission from fuel combustion products, storage, and use of hazardous substances and fuels, contamination of soil and water sources, asbestos, and noise. Sorek 2 will be required to comply with the requirements and to receive appropriate permits in accordance with this legislation, and in accordance with the division between Sorek 2 and IDE. In the Gat Power Plant, the operation and maintenance contractor (Siemens) is in charge of compliance with the environmental protection regulations, which are relevant to the power plant, and its compliance with the provisions of the law is monitored on a monthly basis. Furthermore, the area of activity has a comprehensive management system designed to ensure that OPC’s power plants comply with all environmental regulations applicable thereto. Failure to comply with the provisions of the environmental laws and the terms of the permits and licenses issued to OPC or their non-receipt under these laws may expose OPC, investees and its directors to criminal and administrative sanctions, including fines and other sanctions, delays in the completion of projects, orders to shut down its facilities, and exposure to expenses for cleaning-up and remediation of environmental damages. Under its risk management policy, OPC adopts procedures for compliance with provisions of environmental laws and terms and conditions of permits and licenses, and continuously monitors ongoing activity, including, among other things, by conducting internal audits. The audits assess several factors, including emissions, handling and storage of hazardous substances, soil and water contamination, noise, etc. The findings are reported based on their severity, and action is taken as quickly as possible. Reports include an immediate report to the facility’s site manager, a monthly report to VP Operations, and a quarterly report to the Health and Safety Committee. To date, no administrative, criminal, and civil legal proceedings have been filed against OPC, alleging violations of environmental laws. For projects under construction, OPC operations are also subject to regulations applicable to the construction of sites, including regulations for the prevention of hazards, safety, and others. Construction is carried out by contractors which have agreements with OPC, and which are subject to the required provisions. Projects under development such as Ramat Bekka and Hadera 2 are required to meet environmental requirements and take actions in order to meet the requirements of the design plans, permits and regulatory provisions in order to meet the terms and conditions for their construction and operation. In this context, it should be noted that according to the additional government resolution to approve Israeli National Infrastructure Plan (or “NIP”) 20B for the construction of Hadera 2, the project is to be built using the best technology available, with the existing Energy Center adjacent to the Hadera Power Plant (including the chimney) being dismantled. In addition, Hadera 2 will execute an environmental project in cooperation with the relevant parties and in accordance with any law until the power plant is operated (if it is constructed). The Clean Air Law As required under the Clean Air Law, OPC holds emission permits for all emission sources under its operation requiring such permits, and acts to renew them from time to time in accordance with the validity period of the expiry date for each power plant (the emission permit for Sorek 2 is handled by IDE). The Hadera Energy Center’s emission permit allows the operation of boilers during limited hours according to a regulatory compliance hierarchy. Zomet’s emission permit prescribes restrictions and guidance on operating hours, including extension of the permitted operating hours by way of written notice by the System Operator, and subject to the System Operator’s approval as defined in the Clean Air Law. By virtue of the Clean Air Law, the System Operator also has the power to require an owner of a generation unit to operate the generation unit beyond the time it is permitted to operate it under the emission permit if a risk situation arises with respect to projects under construction in consumers’ premises; in some of the projects, the consumer’s emissions permit should be updated regarding the activity of the generation facility being constructed by OPC, and OPC is acting and will act to update the permits as needed. There is no certainty that the required emission permits will be obtained (and this may involve certain procedures or objections); failure to obtain the permits may have an adverse effect on the completion of the relevant on-site facilities and/or undertakings for completion dates under agreements with the customers. 120 Soil and water In Rotem, Hadera, and Zomet, hazardous substances are present and stored, as well as infrastructure and facilities containing fuels and hazardous substances. OPC has indicated that it strives to prevent soil and water contamination from these substances, infrastructure, and facilities. Effluents During production, it is required to dispose of the effluents involved in the production process and operation of the facilities. At the Hadera Power Plant, fresh make-up water removal from the power plant to the Hadera Sewage Treatment Plant was arranged. In Rotem, industrial effluents are collected and reused at the Rotem power plant (owned by Israel Chemicals Ltd). Zomet directs the water to the Netiv HLH water reservoir. Gat directs the effluents to the Gat sewage treatment facility. Hazardous substances OPC holds, uses, and stores hazardous substances at OPC’s sites for its routine activity. Rotem, Hadera, Gat, Zomet and the Hadera Energy Center have poison permits which are renewed once a year. Planning and construction As part of the area of activity, OPC is subject to the environmental aspects of its activity, including the provisions of planning and construction laws. As part of the application of planning and construction regulations, OPC’s power plants and projects under construction are subject to environmental regulations set out in master plans and construction permits. Business licensing The active power plants operate in accordance with several business licenses which are in force in accordance with the Business Licensing Order (Businesses Requiring Licenses), 2013, and pursuant to the conditions accompanying the licenses, which are revised or renewed from time to time. These are intended to regulate the activities of the power plant, among other things, to mitigate and prevent environmental risks and hazards. When constructing on-site electricity generation facilities, the business licenses of the consumers may require amendment or an additional business license to be issued for this purpose. Integrated environmental regulation In September 2024, the Environmental Protection Law (Streamlining Environmental Licensing Procedures) (Legislative Amendments), 2024, came into force, as part of which indirect amendments were made to the Clean Air Law, the Hazardous Substances Law, the Environmental Protection Law (Supervisory and Enforcement Powers), 2011, the Administrative Affairs Court Law, 2000, and the Center for Collection of Penalties, Fees and Expenses Law, 1995. The law prescribes a unified environmental permit arrangement that supersedes the need to obtain several types of permits for the activity of plants and businesses, which have the potential to cause hazards and risks to public health and the environment, and includes conditions that regulate all the effects of the occupation requiring the permit on the public and the environment (air pollution, wastewater, nuisance and hazards, etc.). The Climate Bill, 2024 In December 2024, the Knesset’s Internal Affairs and Environment Committee approved the second and third readings of the Climate Bill. The proposed law establishes a national strategic net zero target for reducing greenhouse gas emissions by 2050 and an interim target of a 30% reduction in emissions by 2030, and stipulates government implementation mechanisms, national plans, and transparency, monitoring and reporting requirements to ensure compliance with the targets. Prior to the approval of the second and third readings of the bill in the Knesset plenum, the proposal will be presented for further discussion by the Ministerial Legislation Committee. As far as OPC is aware, legislation proceedings have not yet been completed, and the final wording of the legislation or the completion of the legislation proceedings are uncertain. 121 United States Regulation permits/licenses In general, CPV’s facilities and operations are regulated under a variety of federal and state laws and regulations. For example, the construction and operation of CPV’s natural gas-fired power plants are subject to permitting and emission limitations pursuant to the Clean Air Act (the “CAA”) and related state laws and regulations that implement the CAA, which laws and regulations and may be stricter than the provisions of the federal CAA depending on the state in which a plant is located. CPV Group is required to hold major source permits (mostly issued by the environmental protection agencies in each state) before the commencement of the construction of such power plants. Depending on air quality in a certain region and its being in line with air quality standards, CPV may be required to obtain emission reduction credit in order to offset potential emissions of each power plant (as it’s the case in connection with natural gas-fired power plants that were or will be built by CPV Group in New York, Connecticut and Illinois). Furthermore, the CPV project companies are generally required to obtain Title V operating permits in order to operate these plants. Such permits will incorporate regulatory standards that apply to air-polluting emissions for natural gas-fired power plants and relevant conditions that are to be met under the building permits issued for such plants. Those standards include technology-based pollution control limitations, and also include restrictions on allowed emissions of SO2 and/or NOx on an annual basis or on the basis of “ozone” season for offsetting annual or ozone season emission, pursuant to the Federal Acid Rain Regulations (which applies in all states to annual SO2 emissions from fossil-to-fuel fired power plants) and the Cross-State Air Pollution Rule. Most of CPV’s natural gas-fired power plants are subject to the Cross State Air Pollution Rule, which requires certain state in the eastern half the United States (“upwind” states) to improve air quality by reducing NOx and/or SO2 emissions of power plants that cross state lines and contribute to smog and soot pollution in the downwind states. In 2015, the United States Environmental Protection Agency (“EPA”) revised its ozone gas standards and states were required to submit state implementation plans by 2018 to comply with the new, more stringent standards. In February 2023, EPA disapproved of 21 states’ submissions; each of these states had proposed taking no action to revise their existing plans. On March 15, 2023, EPA issued a federal implementation plan, called the “Good Neighbor Plan,” covering 23 states which would impose requirements on fossil fuel-fired plants and industrial sources. The Good Neighbor Plan establishes an allowance-based NOx emissions trading program for power plants in order to ensure that emissions from upwind states do not interfere with downwind states’ ability to achieve and maintain compliance with the 2015 ozone national ambient air quality standard. There have been numerous lawsuits filed challenging the Good Neighbor Plan and related EPA actions and after the Supreme Court stayed implementation of the rule for those stages which had sought such a stay, on November 6, 2024, the EPA issued an interim final rule staying enforcement of the Good Neighbor Plan with respect to all sources covered by the Good Neighbor Plan, not just those who were subject to prior judicial stays. On January 27, 2026, the EPA proposed the first phase of its reconsideration of the Good Neighbor Plan. Under this rule, the EPA would approve eight state implementation plans that were previously disapproved under the previous administration’s application of the Good Neighbor Plan. These eight states are: Alabama, Arizona, Kentucky, Minnesota, Mississippi, Nevada, New Mexico, and Tennessee. Under this approach, these states will be deemed to have fulfilled their obligation to avoid interfering with other states’ ability to meet the 2015 8-hour ozone standard. If the first phase of this plan is finalized, the EPA has indicated that it will approve the state implementation plans of five other states (Arizona, Iowa, Kansas, New Mexico, and Tennessee) which were previously disapproved by the prior administration. Federal regulations require entities to report the emission of greenhouse gases emissions under the Clean Air Act (CAA). The CAA regulates emissions of air pollutants from various industrial sources, such as natural gas-fired power plants, including by requiring Title V Permits to Operate for such sources of air pollution emissions above certain thresholds. Furthermore, federal regulations also impose restrictions on carbon dioxide emissions from new combined cycle plants (whose construction commenced after January 8, 2014) or reconstructed (commenced reconstruction after June 8, 2014) combined-cycle power plants. States may also impose additional regulations or limitations on such emissions. For example, CPV’s natural gas-fired power plants in Connecticut, New York, New Jersey and Maryland are subject to the Regional Greenhouse Gas Initiative (“RGGI”), which requires CPV’s natural gas-fired plants to obtain, either through auctions or trading, greenhouse gas emission allowances to offset each facility’s emission of CO2. In its Title V application process, Valley was required to address New York legislation on such matters. Regulated by the RGGI, an independent regulator that regulates auctions for carbon dioxide allowances, as well as activity in the secondary market, to ensure honesty and security in the market. 122 A legal proceeding was held in the state of Pennsylvania regarding whether the sale of carbon dioxide allowances pursuant to Pennsylvania’s carbon cap and trade budget program is an authorized “fee” or a “tax” that can only be imposed by the state legislature. On November 1, 2023, a Pennsylvania court ruled that the RGGI constitutes a tax that requires legislative processes in order to enter into effect. This decision cancels the Pennsylvania governor’s plan to impose RGGI by means of an administrative decision. Based on press release this initiative of Pennsylvania Governor was dropped at this stage. In April 2024 the U.S. EPA published final rules (the “April 2024 GHG Rules”) setting standards for greenhouse gases emissions’ regulations in the framework of the CAA from existing coal-fired plants and new natural gas plants. Pursuant to the new rules, up to January 1, 2032, a reduction of emissions will be required at a carbon capture rate of 90% for coal-fired generation facilities that are expected to operate after 2039 and new baseload natural gas-fired generation facilities (that were not under construction as of May 2023). Less stringent requirements were provided for, among other things, existing coal-fired generation facilities that integrate natural gas fired generation that are expected to discontinue their operations prior to 2039. For new gas turbines, the regulations require that full baseload (as defined) generation through use of natural gas combustion will be executed with maximum utilization of efficient technologies in order to limit emissions to no more than 800 lbs. CO2/MWh-gross until January 1, 2032, and thereafter a reduction to 100 lbs. CO2/MWh-gross via 90% carbon capture or co-firing with hydrogen. Efficiency requirements and reduced emission restrictions were provided with respect to gas turbines that generate at a partial baseload or a low baseload. The various states would have two years to develop compliance plans for the existing coal plants but compliance for new natural gas plants (the construction of which started after 2023) is immediate. In July 2024, the U.S. Appeals Court rejected a request for an injunctive order filed by several state attorneys general with respect to the April 2024 GHG Rules, which was intended to stay their enforcement. In October 2024, the U.S. Supreme Court rejected a request to delay implementation of the April 2024 GHG Rules such that they would remain in effect so long as the court proceedings (deliberations) are ongoing. However, after commencing office, President Trump issued an executive order for all federal agencies, including the EPA, to review and identify existing regulations and policies that unduly burden domestic energy resources and develop and begin implementing plans to expeditiously suspend, revise or rescind the identified regulations and policies. Such reviews remain ongoing and it is not known what actions, if any, the EPA will take with respect to these rules. On June 11, 2025, EPA proposed a rule that would repeal all greenhouse gas standards under Section 11 of the CAA applicable to the power sector, including the April 2024 GHG Rules. To the extent the April 2024 GHG Rules are implemented in the manner they were published, the development portfolio of CPV Group, which includes wind energy and solar projects and Low Carbon Projects may benefit from a tailwind due to such regulation. In addition, in the estimation of CPV Group its operational natural gas powered power plants may have a competitive advantage under such regulation in light of their high level of efficiency (as relatively new plants) along with entry barriers associated with the construction of new natural gas powered power plants. If the proposed repeal is finalized, the effect on CPV Group is uncertain at this time. Furthermore, 24 states (including Maryland, New York, New Jersey, Connecticut and Illinois, states in which CPV Group operates), the District of Columbia and Puerto Rico adopted legislative agendas and/or administrative orders in order to achieve carbon neutrality or 100% zero-emission electricity supply within the next 20-30 years. CPV’s natural gas-fired projects are also subject to regulation under the federal Clean Water Act (the “CWA”) and related state laws in connection with any discharges of wastewater and storm water from its facilities. The CWA prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits, including wastewater and stormwater permits under the National Pollutant Discharge Elimination System. The discharge of wastewater into public water sources may be subject to federal standards (depending on the source of the wastewater). For discharges from a facility that are directed to a publicly owned treatment works, the main regulator that regulates such discharges is, generally, a municipal authority that operates system for treating the wastewater. The projects of CPV are also subject, as applicable, to requirements under federal and state laws governing the management, disposal and release of hazardous and solid wastes and materials at or from its facilities, including the federal Resource Conservation and Recovery Act (“RCRA”) and the CERCLA (and equivalent state laws). RCRA requires owners and operators of facilities that generate and dispose of hazardous waste in third-party sites to obtain facility identification numbers from the EPA and to comply with the regulations that apply to storage and disposal of such waste. Facilities that store hazardous waste for periods longer than those set in the regulations, or which treat or dispose of the hazardous waste in the facility’s site are required to hold such a permit and operate in accordance with the provisions of RCRA Subtitle C permits. CPV facilities are operated in a manner whereby they are not required to RCRA Subtitle C permits. 123 CERCLA, together with other state laws, stipulate that the current or previous owners, that operated facilities in which hazardous substances were discharged to the environment, or which transported waste containing hazardous substances to third parties’ waste sites, might be held liable by the United States government, state agencies or private entities, in respect of response costs borne by such entities to investigate and treat pollution in these sites, or that might be subject to orders to investigate and treat such pollution as issued by the EPA or state agencies (under state regulations). Parties that were found liable under the CERCLA might also be found liable to damages caused to natural resources as a result of discharge of waste as stated above. Generally, parties that were found liable under the CERCLA and similar state laws are not covered by the defense claim whereby they acted in accordance with the applicable law. Furthermore, the liability generally applies “jointly and severally”; that is to say, the liable party may be liable to a share of the response costs amount that is larger than its share in the disposal of waste in the relevant site. The sites and operation of CPV’s renewable power projects are subject to a variety of federal environmental laws, including with respect to protection of threatened and endangered plant and animal species, such as the Endangered Species Act, the Migratory Bird Treaty Act, and the Bald and Golden Eagle Protection Act. These laws and their state and local equivalents provide for significant civil and criminal penalties for unpermitted activities that result in harm to or harassment of certain protected animals and plants, including damage to their habitats. CPV Group’s operations in areas where there are threatened or endangered species, or in areas where there are critical natural habitats, may require certain permits or be subject to harsh restrictions or requirements to take protective measures in connection with these species. CPV Group may also be prevented from developing projects in these areas. Furthermore, CPV Group’s natural gas-fired projects are also subject to the above laws although to a lesser extent than wind and solar. Projects that were awarded federal funding, or which are required to obtain a federal permit or other discretionary permit (except for a number of exceptions) are subject to the National Environmental Protection Act (“NEPA”), that requires federal agencies to assess the potential environmental impact of those permits and approvals. For example, if, due to the project’s impact on the ‘Waters of the U.S.’, it is required to hold an ‘Individual Section 404 Permit’ issued by the United States Army Corps of Engineers (the “ACOE”), which permits such an impact, then the project will be required to undergo an environmental impact survey under NEPA. The environmental impact survey might cause significant delays in the project’s development, depending on the project’s potential environmental impact. If a project is required to obtain federal approval, it will also be subject to the National Historic Preservation Act, which requires federal agencies to consider the effects of federal projects on significant historic, cultural and archaeological resources. CPV Group’s project companies may be subject to other federal permits, licensing arrangements, approvals and other requirements by other federal agencies under various legislation, including the Advisory Council on Historic Preservation; the ACOE referred to above (in connection with the ‘Waters of the U.S.’); the United States Fish and Wildlife Service in connection with potential effects on endangered species, migratory birds, certain species of eagle, and natural habitats that are critical for those animals; and the Federal Bureau of Land Management, in connection with projects that require the use of federal land managed by the federal government. Local or state regulations (including dedicated regulations requiring entities to obtain conditional or special use permits for the purpose of building a project), including, for example, the New York Accelerated Renewable Energy and Community Benefit Act (that applies to large-scale renewable energy projects in New York), may require a similar consultation with state agencies and/or conducting environmental impact surveys in accordance with state laws. CPV’s operations also are subject to a number of federal and state laws and regulations designed to protect the safety and health of workers, including the Federal Occupational Safety and Health Act, and equivalent state laws. Permits/licenses required in connection with operational projects As part of its activities, CPV is required to obtain and hold permits due to various federal, state and local legislation and regulations relating to power plant operations and environmental protection. Such permits are required both due to the activities of the power plants involving generation therein based on natural gas and the impact of the generation process on the air and water in the area of the facilities, as well as a result of construction of the renewable energy facilities (wind farms and solar fields) that could constitute environmental hazards and have a harmful impact on the area in which they are located. The main required permits/licenses (without distinction between different requirements of the various jurisdictions in which the power plants / facilities are located): • CPV is required to hold permits in order to operate and/or construct the power plants, the purpose of which is prevention or reduction of air pollution. The power plants may also be required to hold permits for flowing water, waste water and other waste into the local sewer systems or into other water sources in the United States. 124 • Due to the height and location of the exhaust stacks and other components of the generation facilities, which could endanger the air traffic, the power plants are required to hold a permit for construction of the stacks and additional components in the generation facilities. This permit is issued by the Federal Aviation Authority (FAA). • Electricity production facilities using renewable energy are often required to hold coverage in accordance with general permits applicable to flood water and, the discharge of dredged and fill materials to the ‘Waters of the U.S.’ Depending on the area of the affected site, these facilities may be required to obtain individual permits from ACOE in respect of those effects; however, generally, it is possible to build projects in places that will not require such permits. • State and local permits for renewable energy facilities (the permit’s requirements depend on the state in which the project is built and its location within the state). All of CPV’s active plants, as well as the plant under construction, hold relevant valid permits for their operational and/or construction activities. With respect to Valley, it commenced operations in January 2018 under a combined Air State Facility and a pre-construction Prevention of Significant Deterioration permit (together, the “ASF Permit”), among other permits and approvals. Valley subsequently filed its Title V Air Permit Application on August 24, 2018, (which is required to replace the ASF Permit) and continued operations under the automatic permit extension provision in the State Administrative Procedure Act, which also extends the ASF Permit. On January 17, 2025, NYSDEC issued a Notice of Complete Application (NOCA) for Valley’s Title V Permit application along with a draft Title V Permit. Following such notice, the remaining administrative permitting process includes several state and federal level procedures. The overall period of this process can reach approximately 18 months (subject to any potential extensions). During 2025 Valley achieved all major permitting milestones required at the state level as follows: completion of legislative hearings; close of written public comment period; submission of comprehensive responses to public comments; confirmation by NYSDEC that no additional information was required; NYSDEC’s transmittal of the final draft permit to the EPA for federal review which took place on December 20, 2025. This initiates EPA’s 45-day review period, during which EPA’s review is focused on confirming that the proposed permit conditions comply with federal CCA requirements and that the permit conditions are federally enforceable. In case no objection, this EPA’s review is followed by a 60-day public petition period, currently expected through April 3, 2026. During the 60-day public petition period third parties may request that EPA object to the Title V permit on defined scope. This step does not affect CPV Valley’s authority to continue operations. Following the public petition period, NYSDEC may issue the final Title V permit. If the NYSDEC denies Valley’s Title V permit application (which as of filing date CPV assumes as unlikely result, based on its advisors), Valley is eligible to submit an administrative appeal on NYSDEC’s decision. If the appeal is submitted within the set timeframe, the relevant directives to the SAPA is expected continue to apply and allow Valley to operate until the completion of the administrative process and determination in the administrative appeal. If an adverse decision is made after the administrative appeals process, Valley may appeal NYSDEC’s final decision to the New York Supreme Court. In such scenario, New York State law allows Valley to seek the court for an order allowing to continue its operation under the SAPA during the pendency of the court proceedings. Valley can continue to operate under the ASF Permit until a final determination (subject to the appeal process) is made regarding the Title V permit. Until the Title V permit is issued (if issued), the terms of the future financing agreements of Valley (one of which was entered into in February 2026 as described above) may be adversely affected. Regulation regarding holding public utility companies A direct or indirect change in ownership or control of voting rights in a corporation that provides infrastructure services (“public utilities”) (including part of the CPV project companies in the U.S.), or in any property used for infrastructure services, may be subject to FERC approval, pursuant to the Federal Power Act. Such approval may also be required for holding the position of officers or directors in corporations that provide infrastructure services or certain other companies that provide financing or equipment for infrastructure services. In addition, the FERC applies the requirements in the Public Utility Holding Company Act of 2005 to direct or indirect holders of 10% or more of the voting rights in companies that, among other activities, own or operate facilities that generate electricity, including renewable energy facilities. There is similar state regulation in several states that regulates ownership or control, directly or indirectly, of voting rights in corporations that provide infrastructure services. Therefore, the acquisition of 10% or more of the share capital of OPC, or Kenon may be subject to the FERC approval, and such direct or indirect acquisition may also be subject to the approval of state regulatory authorities in some U.S. states where either company has business operations. 125 On January 21, 2025, President Trump issued an executive order pausing federal permitting, approvals and federal loans for all onshore and offshore wind projects while the Department of Interior performs an assessment of federal wind leasing and permitting practices. Property taxes/community payments In general, each CPV project company is subject to property taxes annually paid to the local jurisdiction in which it is located. In some cases (Shore, Maryland, Valley, Towantic, Basin Ranch, Maple Hill, Backbone and Stagecoach), the projects have come to an arrangement for a long-term payment which replaces the regular assessment and taxation process or recognizes certain exemption provisions in relevant laws or regulations. The long-term payment arrangements run between 20 and 35 years from COD for each applicable project. In other cases (Fairview and Keenan), the projects are subject to an annual assessment on the value of their taxable property and then pay property taxes at the relevant taxing jurisdiction rates. Certain CPV project companies (Fairview and Valley) entered into agreements for the benefit of community purposes in their respective local communities. The long-term payments by virtue of such agreements fund community entities or reimburse the local community for the impact during construction. These payments are spread over periods of 20 to 30 years from COD. Renewable Energy The Inflation Reduction Act of 2022 In 2022, the IRA was signed into law by President Biden. Among other things, this law created new and enhanced existing significant tax benefits to renewable energies and technologies aimed at reducing carbon emissions. One of the IRA’s key objective is to increase the production of electricity using renewable energies and to increase regulatory stability in this sector. Following changes of administrations after the 2024 elections and the enacting of the OBBBA the tax benefits under the IRA for wind and solar projects were limited. Under the OBBBA and the IRS “Safe Harbor” rules the tax benefits for wind and solar projects detailed below will be applicable to those projects meeting the conditions of the Safe Harbor only while low carbon tax benefits were not adversely affected by the OBBBA. Following are key arrangements set forth in the IRA which may be relevant for CPV Group’s activities: The IRA includes a number of benefits available to renewable energy projects. The IRA extends the ITC and the PTC for renewable energy projects that commenced construction before January 1, 2025. The base level for the investment tax credit is 6% and the base level for the production tax credit is 0.3 cents/kWh (adjusted for inflation). Projects that meet prevailing wage and registered apprenticeship requirements may be eligible for an investment tax credit of up to 30% or a production tax credit of up to 1.5 cents/kWh (adjusted for inflation). Bonus credit amounts, may be earned, increasing by 10% the PTC or 10 percentage points the ITC if the applicable project meets domestic steel, iron and manufactured products requirements. An additional bonus credit amounts may also be earned, increasing by 10% the PTC or 10 percentage points the ITC if the applicable project is located in specially designated energy communities, such as (i) brownfield sites, (ii) locations with above national average unemployment and oil, gas or and/or coal industry contributions to direct employment or local tax revenues above specified levels, and (iii) census tracts in or adjacent to those in which a coal mine has closed since December 31, 1999, or coal-fired power plant has closed since December 31, 2009. 126 Electric generation projects placed in service after December 31, 2024, that emit zero or less greenhouse gases are eligible for a technology neutral ITC or PTC established under IRA, at the same credit levels as described above for the existing ITC. These tax credits are subject to phase out, starting from the later of 2034 and when U.S. greenhouse gas emissions from electricity generation equal or are less than 25% of 2022 electricity generation emissions levels. Projects eligible for these tax credits will also be eligible to use 5-year accelerated depreciation for project assets. CPV Group opted for an ITC for Maple Hill, Backbone and Rogue’s Wind at the rate of 40% and opted for a PTC for Stagecoach. Qoros Kenon holds a 12% interest in Qoros, a China-based automotive company. Kenon previously held a 50% stake in Qoros prior to the Majority Qoros Shareholder’s investment in Qoros, and was one of the founding members of the company. The Majority Qoros Shareholder holds 63% of Qoros and Chery holds 25%. Substantially all of Quantum’s interest in Qoros is pledged to secure Qoros’ RMB 1.2 billion loan facility. In April 2021, Kenon’s subsidiary Quantum entered into a Sale Agreement with the Majority Qoros Shareholder to sell its remaining 12% interest in Qoros for RMB 1.56 billion (approximately $223 million) and Baoneng Group provided a guarantee of the Majority Qoros Shareholder’s obligations under the Sale Agreement. The Majority Qoros Shareholder had not made any of the required payments under the Sale Agreement, and in the fourth quarter of 2021, Quantum initiated arbitral proceedings against the Majority Qoros Shareholder and Baoneng Group with CIETAC. In February 2024, CIETAC issued a final award in favor of Quantum. The tribunal ruled that the Majority Qoros Shareholder and Baoneng Group are obligated to pay Quantum an amount equal to the purchase price set forth in the Sale Agreement (as adjusted for inflation) of approximately RMB 1.7 billion (approximately $243 million), together with pre-award and post-award interest (which will accrue until payment of the award), legal fees and expenses. Such decision is final and is not subject to appeal in accordance with the laws of the People's Republic of China, with the total amount currently being approximately RMB 2.2 billion (approximately $315 million). In connection with its initial investment in Qoros, the Majority Qoros Shareholder had agreed to assume Quantum’s obligations relating to Quantum’s pledge of its remaining shares in Qoros. In lieu of assuming such pledge obligations, Baoneng Group provided a guarantee to Kenon in respect of a number of obligations, including an obligation of the Majority Qoros Shareholder to reimburse Kenon in the event that Quantum’s shares are foreclosed upon and obligation of Baoneng Group to deposit into escrow amounts sufficient to protect Kenon against losses in the event of a foreclosure over Quantum’s shares in Qoros by having amounts available to repay any defaulted amounts. Baoneng Group failed to comply with the obligations of the guarantee and as a result, in November 2021, Kenon filed a claim for specific performance against Baoneng Group at the Shenzhen Intermediate People’s Court relating to the breaches of the guarantee agreement by Baoneng Group; the case was transferred to the Supreme People’s Court for trial. The Supreme People’s Court upheld Kenon’s claim for specific performance against Baoneng Group, ordering Baoneng Group to open an escrow account on behalf of Kenon and to deposit approximately RMB 1.4 billion (approximately $200 million) into the escrow account (the “Guarantee Award”). In connection with the CIETAC Award and the Guarantee Award, Kenon has obtained court orders freezing assets of Baoneng Group, primarily comprising equity interests in entities owning directly and indirectly listed and unlisted equity interests in various businesses; such assets are also subject to freezing orders by other creditors and the orders obtained by Kenon are at various rankings as among creditors. As Baoneng Group had failed to uphold its obligations under the CIETAC Award and the Guarantee Award, Kenon has initiated enforcement and other legal proceedings. There is no assurance as to the outcome of these proceedings. There is also no assurance that Baoneng Group will pay or has the ability to pay the judgments against it in our favor. Kenon is engaged in discussions with the Baoneng Group on the outstanding awards. Any value that could be realized in respect of these awards is subject to significant risks and uncertainties, including the risk that Quantum may be unable to enforce the awards or otherwise collect the amounts awarded or otherwise owing to it, risks relating to any action that may be taken seeking to challenge enforcement of the award, risks relating to the process for enforcement of the awards in these proceeding/jurisdiction, risks relating to the financial condition of the parties subject to the awards, risks related to the value in respect of any frozen assets pursuant to court orders as well as the risk of competing claims to such assets and Kenon’s ability to realize any value in respect of such assets or otherwise in connection with the awards, including the risk that Kenon does not realize any value from such assets or otherwise in connection with these awards and that any value that is realized is less than the amounts owed to Kenon and other risks and uncertainties, which could impact Quantum’s ability to realize any value from this award. 127 Qoros has been in default under certain loan facilities for a number of years, including its RMB 1.2 billion loan facility, which is secured by, among other collateral, all of Kenon's shares in Qoros. The lenders under Qoros' RMB 1.2 billion loan facility and Kenon has been informed that lenders under various other Qoros debt facilities have made court applications for enforcement proceedings in respect of such defaulted loans and pledges and guarantees, and some of these applications have been accepted by the courts, including enforcement with respect to certain assets of Qoros which may have a material adverse impact on Qoros’ ability to resume operations in the future. The lenders under Qoros' RMB 1.2 billion loan facility have brought enforcement proceedings to enforce Quantum’s pledge of its 12% interest in Qoros which had been pledged to secure this loan. In addition, Kenon has been informed that in December 2025, an application was made to the Suzhou Intermediate People's Court for bankruptcy reorganization of Qoros and that the application is currently under review by the court. We face risks in connection with each of the foregoing and the impact thereof. There is no assurance as to the collection of the arbitration award and the outcome of legal proceedings described above or any value Kenon may realize in respect of its remaining shares in Qoros. Since April 2020, Kenon no longer accounts for Qoros pursuant to the equity method of accounting and in 2021, Kenon wrote down the value of Qoros to zero. We are party to a joint venture agreement (the “Joint Venture Agreement”), with respect to our and our joint venture partners’ interest in Qoros. The Joint Venture Agreement sets forth certain rights and obligations of each of Quantum, the wholly-owned subsidiary through which we own our equity interest in Qoros, Wuhu Chery and the Majority Qoros Shareholder with respect to Qoros. The Joint Venture Agreement is governed by Chinese law. Under the Joint Venture Agreement, certain matters require the unanimous approval of Qoros’ board of directors, while other matters require a two-thirds or a simple majority board approval. Pursuant to the terms of the Joint Venture Agreement, we have the right to appoint two of Qoros’ nine directors. For further details, see “Item 3.D—Risks Related to Our Strategy and Operations—We face risks in relation to our remaining 12% interest in Qoros, including risks relating to the enforcement and/or collection of the arbitration award and guarantee award in our favor.” Claim Relating to the Inkia Business, which Kenon sold in 2017 In November 2017, Kenon, through its subsidiaries Inkia and IC Power Distribution Holdings Pte. Ltd. (“ICPDH”), entered into a share purchase agreement to sell all of their interests in power generation and distribution companies in Latin America and the Caribbean (the “Inkia Business”). Set forth below is a description of the investment treaty claim that is being pursued by Kenon and a subsidiary in connection with the Inkia Business. Bilateral Investment Treaty Claim Relating to Peru In June 2017 and November 2018, IC Power and Kenon respectively sent Notices of Dispute to the Republic of Peru under the Free Trade Agreement between Singapore and the Republic of Peru (the “FTA”), relating to two disputes described below, based on events that occurred while Kenon, through IC Power, owned and operated their Peruvian subsidiaries Kallpa and Samay I, later sold as part of the Inkia sale. The first concerned Secondary Frequency Regulation and the second concerned the use of the secondary and complementary transmission systems (“Transmission Tolls”). The claims are described in detail in prior disclosures. On June 12, 2019, IC Power and Kenon filed a Request for Arbitration with the International Centre for Settlement of Investment Disputes (“ICSID”) against Peru alleged breaches of the FTA. On October 4, 2023, an arbitration tribunal constituted by ICSID delivered a final award (the “Award”). The parties each submitted requests to rectify and/or clarify aspects of the Award pursuant to Article 49 of the ICSID Convention. On May 3, 2024, the arbitration tribunal issued its Decision on the Requests for Rectification and Clarification, which supplemented and became part of the Award. In its Award, the arbitration tribunal concluded that Peru’s resolution relating to secondary frequency regulation breached Peru’s obligations under Article 10.5 of the FTA. The tribunal dismissed the claim relating to Transmission Tolls. Pursuant to the Award, Peru has been ordered to pay Kenon and IC Power a total of $110.7 million in damages together with $5.1 million in fees and costs and pre-award and post-award interest. In accordance with the Award, pre-award interest is payable on the damages awarded from November 24, 2017 to the date of the Award at Peru’s cost of debt, which is calculated to be at a rate of 6.91% per annum, compounding annually. Post-award interest is payable from the date of the Award at the same rate. As of March 30, 2026, pre- and post-award interest on the Award is in excess of $82 million. Interest will continue to accrue until the Award is paid. 128 On November 14, 2023, Kenon and IC Power filed an action in the U.S. District Court for the District of Columbia seeking recognition of and the entry of judgment on the Award in the United States. On August 22, 2024, ICSID provided Kenon and IC Power with Peru’s application for the partial annulment of the ICSID Award (the “ICSID Annulment Application”). With its ICSID Annulment Application, Peru requested a stay on the enforcement of the Award. Enforcement of the Award shall be stayed until the annulment proceeding has concluded. On October 18, 2024, ICSID appointed an ad hoc committee to decide the ICSID Annulment Application. The hearing on partial annulment occurred on December 10 and 11, 2025. The decision on partial annulment is currently pending. IC Power and Kenon have entered into an agreement with a capital provider to provide capital for expenses in relation to the pursuit of their arbitration claims against the Republic of Peru and other costs. The obligations of Kenon and IC Power are secured by pledges relating to the agreement. Security has been provided relating to the obligations of Kenon and IC Power. The agreement contains certain representations and covenants by IC Power and Kenon and events of default in event of breach of such representations and covenants. In the event that Kenon or IC Power receives proceeds in connection with the Award or settlement thereof, the capital provider will be entitled to be repaid the amount committed by the capital provider and to receive a portion of the claim proceeds, including interest. The capital provider will be entitled to be repaid the amount committed by the capital provider (which to date has equaled $12 million) and to receive up to approximately 55% of the net claim proceeds, subject to the terms of the agreement among Kenon, IC Power and the capital provider. As of March 30, 2026, Kenon estimates that its share of the Award, including interest and net of arbitration costs, would be approximately $90 million, subject to tax. C. Organizational Structure The chart below represents a summary of our organizational structure, excluding intermediate holding companies, as of December 31, 2025. This chart should be read in conjunction with the explanation of our ownership and organizational structure above. 129 D. Property, Plants and Equipment For information on our property, plants and equipment, see “Item 4.B Business Overview.”