# Ormat Technologies, Inc.: Form 10-K for the period ended Dec 31, 2022

- Company: [Ormat Technologies, Inc.](/companies/ora.md) (CIK 1296445)
- Form: 10-K
- Filed: 2023-02-24
- Accepted by EDGAR: Feb 24, 2023, 09:27 ET
- Period: 2022-12-31
- Accession: 0001437749-23-004477
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1296445/000143774923004477/ora20221231_10k.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1296445/000143774923004477/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2022-12-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 12 months, 2022-01-01 to 2022-12-31 | $734.2m | us-gaap:RevenueFromContractWithCustomerIncludingAssessedTax |
| Cost of revenue | 12 months, 2022-01-01 to 2022-12-31 | $465.3m | us-gaap:CostOfGoodsAndServicesSold |
| Gross profit | 12 months, 2022-01-01 to 2022-12-31 | $268.8m | us-gaap:GrossProfit |
| Research and development | 12 months, 2022-01-01 to 2022-12-31 | $5.1m | us-gaap:ResearchAndDevelopmentExpense |
| Operating income | 12 months, 2022-01-01 to 2022-12-31 | $152.8m | us-gaap:OperatingIncomeLoss |
| Interest expense | 12 months, 2022-01-01 to 2022-12-31 | $87.7m | us-gaap:InterestExpense |
| Income tax | 12 months, 2022-01-01 to 2022-12-31 | $14.7m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 12 months, 2022-01-01 to 2022-12-31 | $65.8m | us-gaap:NetIncomeLoss |
| Diluted EPS | 12 months, 2022-01-01 to 2022-12-31 | $1.17 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 12 months, 2022-01-01 to 2022-12-31 | $1.17 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 12 months, 2022-01-01 to 2022-12-31 | 56,503,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 12 months, 2022-01-01 to 2022-12-31 | $281.0m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 12 months, 2022-01-01 to 2022-12-31 | $563.5m | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Dividends paid | 12 months, 2022-01-01 to 2022-12-31 | $27.1m | us-gaap:PaymentsOfDividendsCommonStock |
| Share repurchases | 12 months, 2022-01-01 to 2022-12-31 | $18.0m | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2022-12-31 | $95.9m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2022-12-31 | $456.7m | us-gaap:AssetsCurrent |
| Total assets | at 2022-12-31 | $4.61bn | us-gaap:Assets |
| Current liabilities | at 2022-12-31 | $343.9m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2022-12-31 | $2.58bn | us-gaap:Liabilities |
| Long-term debt | at 2022-12-31 | $2.05bn | us-gaap:LongTermDebt |
| Shareholders' equity | at 2022-12-31 | $1.87bn | us-gaap:StockholdersEquity |

## Business

As filed, 144,907 characters.

### Overview

We are a leading vertically integrated company that is primarily engaged in the geothermal energy power business. We leverage our core capabilities and global presence to expand our activity in recovered energy generation and into different energy storage services and solar PV (including hybrid geothermal and solar PV as well as Solar plus Energy Storage). Our objective is to become a leading global provider of renewable energy and help to mitigate climate change by providing replacement to carbon-intensive energy sources. We have adopted a strategic plan to focus on several key initiatives to expand our business.

We currently conduct our business activities in three business segments:

- *Electricity Segment.* In the Electricity segment, we develop, build, own and operate geothermal, solar PV and recovered energy-based power plants in the United States and geothermal power plants in other countries around the world and sell the electricity they generate. In 2022 we commenced commercial operation of 78 MW of geothermal power plants including the 35MW CD4 power plant in the Mammoth complex and the 13MW Tungsten 2 plant, both in the U.S. In addition, we commenced commercial operation of 30MW of Solar PV projects, including the 20MW Wister solar power plant as well as the 5MW Steamboat Hills and the 5MW Tungsten Solar power plants.
- *Product Segment.* In the Product segment, we design, manufacture and sell equipment for geothermal and recovered energy-based electricity generation and provide services relating to the engineering, procurement and construction of geothermal and recovered energy-based power plants. Since the beginning of 2022, we signed new contracts that were added to our backlog and secured $155.5 million of revenues to be recognized over the next two years.
- *Energy Storage Segment*. In the Energy Storage segment, we own and operate grid connected In Front of the Meter (IFM) BESS facilities, which provide capacity, energy and ancillary services directly to the electric grid.In 2022, we commissioned one energy storage facility with a total of 5MW/20 MWh in California.

The charts below show the relative contributions of each of our segments to our consolidated revenues and the geographical breakdown of our segment revenues for the fiscal year ended December 31, 2022.

The following chart sets forth a breakdown of our revenues for each of the years ended December 31, 2021 and 2022:

The following chart sets forth the geographical breakdown of revenues attributable to our Electricity and Product segments for each of the years ended December 31, 2021 and 2022:

The revenues attributable to our Energy Storage segment for each of the years ended December 31, 2021 and 2022 were 100% generated in the United States.

### Our Power Generation Business (Electricity Segment)

Our company-owned power plants include both power plants that we have built and power plants that we have acquired. The substantial majority of the power plants that we currently own or operate produce electricity from geothermal energy sources. Geothermal energy is a clean, renewable and generally sustainable form of energy derived from the natural heat of the earth. Unlike electricity produced by burning fossil fuels, electricity produced from geothermal energy sources is produced without emissions of certain pollutants such as nitrogen oxide, and with far lower emissions of other pollutants such as carbon dioxide. As a result, electricity produced from geothermal energy sources contributes significantly less to climate change and local and regional incidences of acid rain than energy produced by burning fossil fuels. In addition, compared to power plants that utilize other renewable energy sources, such as wind or solar, geothermal power plants are generally available all year-long and all day-long and can therefore provide base-load electricity services. Geothermal power plants can also be custom built to provide a range of electricity services such as baseload, voltage regulation, reserve and flexible capacity.

We own and operate geothermal and solar PV hybrid projects and have similar projects currently under construction, in which the electricity generated from a solar PV power plant is used to offset the equipment’s energy use at the geothermal facility, thus increasing the geothermal energy delivered by the project to the grid. In 2022 we commenced operations in a 20MW stand-alone Solar PV project in California.

We also construct, own, and operate recovered energy-based power plants. We have built all of the recovered energy-based plants that we operate. Recovered energy comes from residual heat that is generated as a by-product of gas turbine-driven compressor stations, solar thermal units and a variety of industrial processes, such as cement manufacturing. Such residual heat, which would otherwise be wasted, may be captured in the recovery process and used by recovered energy power plants to generate electricity without burning additional fuel and without additional emissions.

Each of our current geothermal power plants sells substantially all of its output pursuant to long-term, and in most of the cases, fixed price PPAs to various counterparties denominated in or linked to the U.S. dollar or Euro. These contracts had a total weighted average remaining term, based on contributions to segment revenue, of approximately 15 years at December 31, 2022. In addition, the counterparties to our PPAs in the United States had a credit rating of between A3 to Baa2 by Moody's and BB- to A by S&P. The purchasers of electricity from our foreign power plants are mainly state-owned entities in countries with below investment grade rating.

### Power Plants in Operation

We own and operate 28 geothermal, REG and solar sites globally with an aggregate generating capacity of 1,070 MW. Geothermal comprised 92% of our generating capacity. In 2022, our geothermal and REG power plants generated at a capacity factor of 83% and 66%, respectively, which is much higher than the 20%-30% capacity factor typically generated in wind and solar projects.

The table below summarizes certain key non-financial information relating to our power plants and complexes as of February 22, 2023. The generating capacity of certain of our power plants and complexes listed below has been updated from our 2021 disclosure to reflect changes in the resource temperature and other factors that impact resource capabilities:

| Type Region Plant | Ownership(1) | Generating capacity (MW) (2) | PPA Tenor | Capacity Factor |
| --- | ---: | ---: | ---: | ---: |
| Geothermal California Ormesa Complex | 100% | 36 | 20 |  |
| Heber Complex | 100% | 81 | 11 | 83%(3) |
| Mammoth Complex | 100% | 65(4) | 14 |  |
| Brawley | 100% | 7(5) | 9 |  |
| West Nevada Steamboat Complex | 100% | 79 | 20 | 81% |
| Brady Complex | 100% | 24 | 27 |  |
| East Nevada Tuscarora | 100% | 18 | 10 |  |
| Jersey Valley | 100% | 8 | 10 |  |
| McGinness Hills | 100% | 146(6) | 16 |  |
| Don A. Campbell | 63.3% | 32 | 13 | 88% |
| Tungsten Mountain | 100% | 42(7) | 21 |  |
| Dixie Valley | 100% | 58 | 16 |  |
| Beowawe | 100% | 14 | 32 |  |
| North West Region Neal Hot Springs | 60% | 24(8) | 16 |  |
| Raft River | 100% | 12 | 10 | 86% |
| San Emidio | 100% | 11 | 16 |  |
| Hawaii Puna | 63.3% | 38(9) | 30 | 62% |
| International Amatitlan (Guatemala) | 100% | 20 | 6 |  |
| Zunil (Guatemala) | 97% | 20 | 12 |  |
| Olkaria III Complex (Kenya) | 100% | 150 | 12 | 76%(10) |
| Bouillante (Guadeloupe Island, France) | 63.75%(11) | 15 | 8 |  |
| Platanares (Honduras) | 100% | 38 | 10 |  |
| Total Consolidated Geothermal |  | 938 |  | 83%(12) |
| REG OREG 1 | 63.3% | 22 | 9 |  |
| OREG 2 | 63.3% | 22 | 12 |  |
| OREG 3 | 63.3% | 5.5 | 7 |  |
| OREG 4 | 100% | 3.5(13) | 7 |  |
| Total REG |  | 53 |  | 66% |
| Solar Tungsten Mountain | 100% | 12 | 21 |  |
| Wister | 100% | 20(14) | 20 |  |
| Steamboat Solar | 100% | 5(15) | 21 |  |
| Total Solar |  | 37 |  |  |
| Unconsolidated Geothermal Indonesia Sarulla Complex | 12.75% | 42 | 25 |  |
| Total Unconsolidated Geothermal |  | 42 |  |  |
| Total |  | **1,070** |  |  |

1\. We have a controlling interest and we operate all of our power plants, except for Sarulla. Financial institutions hold equity interests in four of our subsidiaries: (i) Opal Geo subsidiaries, which own the McGinness Hills Phases 1 and 2 geothermal power plants, the Tuscarora and Jersey Valley power plants and the second phase of the Don A. Campbell power plant, all located in Nevada; (ii) ORNI 41, which owns McGinness Hills Phase 3 located in Nevada; (iii) ORNI 43, which owns the Tungsten Mountain geothermal power plant located in Nevada; (iv) Steamboat Hills, LLC, which owns the Steamboat Hills power plant located in Nevada; and (v) CD4 partnership that owns the CD4 power plant, under Mammoth Complex, in California. In the table above, we list these power plants as being 100% owned because all of the generating capacity is owned by these subsidiaries and we control the operation of the power plants. The nature of the equity interests held by the financial institution is described below in Item 8 — “Financial Statements and Supplementary Data" under Note 13.

We own a 63.75% equity interest in the Bouillante power plant, a 60% equity interest in the Neal Hot Spring power plant and a 63.25% direct equity interest in each of the Puna plant, the first phase of Don A. Campbell, OREG 1, OREG 2 and OREG 3 power plants as well as the indirect interest in the second phase of the Don A. Campbell complex owned by our subsidiary, ORPD. We list 100% of the generating capacity of the Bouillante power plant, the Neal Hot Springs power plant and the power plants in the ORPD portfolio in the table above because we control their operations. We list our 12.75% share of the generating capacity of the Sarulla complex as we own a 12.75% minority interest. Revenues from the Sarulla complex are not consolidated and are presented under “Equity in earnings (losses) of investees, net” in our consolidated financial statements.

2\. References to generating capacity generally refer to gross generating capacity less auxiliary power. We determine the generating capacity of these power plants by taking into account resource and power plant capabilities. In any given year, the actual power generation of a particular power plant may differ from that power plant’s generating capacity due to variations in ambient temperature, the availability of the geothermal resource, and operational issues affecting performance during that year. In 2022 the capacity factors of Brawley, Olkaria, Puna, Heber and Sarulla complexes were significantly impacted by operational and resource issues, as discussed further under "Description of our power plants".

3\. Capacity factor excludes the Heber 1 plant that was shutdown following a fire in early 2022, as discussed further under "Description of our power plants".

4\. The Mammoth complex includes 35MW from CD4 that commenced commercial operation in July 2022.

5\. The generating capacity of the Brawley complex is reduced due to lower performance of the wellfield.

6\. Generating capacity reduced by 14MW to reflect the cooling we are experiencing in the resource. We are evaluating our alternatives to mitigate the cooling.

7\. The Tungsten Mountain complex includes the 13MW second phase that commenced commercial operation in April 2022. Tungsten Mountain is a hybrid geothermal and solar power plant that uses the solar energy for geothermal power plant auxiliary power. The solar power plant's capacity increased in the third quarter of 2022 by 5MW to a total of 12 MW and is presented separately in the table above.

8\. We own 60% and Enbridge owns 40% of the Neal Hot Springs power plant.

9\. The Puna geothermal power plant shut down on May 3, 2018 when the Kilauea volcano erupted following a significant increase in seismic activity in the area. The Puna power plant resumed operations in November 2020 and during 2022 operated at a level of 23-25 MW. We are currently negotiating an amendment to the economic terms of the PPA.

10\. Capacity factor was mainly impacted by lower performance of Olkaria complex, as further discussed below under "Description of our Power plants".

11\. We own 63.75%, CDC owns 21.25% and Sageos owns 15.0% of the Bouillante power plant.

12\. The total availability of the geothermal power plants excludes the Puna and Heber 1 power plants that are not in full operation, as discussed above.

13\. The OREG 4 power plant is not operating at full capacity due to low run time of the compressor station that serves as the power plant’s heat source. This has resulted in lower power generation.

14\. The 20MW Wister Solar power plant commenced commercial operation in July 2022.

15\. The 5MW Steamboat Solar project commenced commercial operation in the second half of 2022.

### New Power Plants

We are currently in various stages of construction of new power plants and expansion of existing power plants. We have released for construction of 91 MW in generating capacity from geothermal and solar PV in the United States and Guatemala. In addition, we have several geothermal and solar PV projects in various stages of development. These projects are primarily located in the United States, Guadeloupe and Indonesia,

We hold substantial land positions across 28 prospects in the United States and 11 prospects in Ethiopia, Guatemala, Honduras, Indonesia, Madagascar and New Zealand that we expect will support future geothermal development. These land positions are comprised of various leases, exploration concessions for geothermal resources, and options to enter into leases. We have started or plan to start exploration activity on many of these prospects.

We expect to add between 230MW to 260MW by the end of 2025 and to reach a total generating capacity of approximately 1.3 GW in the Electricity Segment by that time.

### Our Product Segment

We design, manufacture and sell products for electricity generation and provide the related services described below. In addition, we provide cementing services for well drilling to third parties. We primarily manufacture products to fill customer orders, but in some situations, we manufacture products as inventory for future projects that we will own or for future third party projects.

### Power Units for Geothermal Power Plants

We design, manufacture and sell power units for geothermal electricity generation, which we refer to as OECs. In geothermal power plants using OECs, geothermal fluid (either hot water, also called brine, steam, or both) is extracted from the underground reservoir and flows from the wellhead to a vaporizer that heats a secondary working fluid, which is vaporized and used to drive the turbine. The secondary fluid is then condensed in a condenser, which may be cooled directly by air through an air cooling system or by water from a cooling tower and sent back to the vaporizer. The cooled geothermal fluid is then reinjected back into the reservoir. Our customers include contractors, geothermal power plant developers, owners and operators.

### Power Units for Recovered Energy-Based Power Generation

We design, manufacture and sell power units used to generate electricity from recovered energy, or so-called “waste heat”. This heat is generated as a residual by-product of gas turbine-driven compressor stations, solar thermal units, biomass facilities and a variety of industrial processes, such as cement manufacturing, and is not otherwise used for any purpose. Our existing and target customers include interstate natural gas pipeline owners and operators, gas processing plant owners and operators, cement plant owners and operators, and other companies engaged in other energy-intensive industrial processes.

### EPC of Power Plants

We serve as an EPC contractor for geothermal and recovered energy power plants on a turnkey basis, using power units we design and manufacture. Our customers are geothermal power plant owners as well as our target customers for the sale of our recovered energy-based power units. Unlike many other companies that provide EPC services, we believe our competitive advantage is in using equipment that we manufacture, which allows us better quality and control over the timing and delivery of required equipment and its related costs.

### Our Energy Storage Segment

Our Energy Storage segment has grown consistently since 2019 and we expect even stronger growth over the coming years. We have targeted the Energy Storage segment as one of our major segments for investment and growth.

In 2022, we successfully brought on line one new Ormat-owned BESS project, the 5 MW/20 MWh Tierra Buena project in California, which increased our operating portfolio at the end of 2022 to approximately 88 MW / 196 MWh within the footprint of 4 RTOs or ISOs: CAISO, PJM Interconnect, ERCOT and ISONE.

We are currently in the process of constructing eight energy storage projects with a total capacity of 204 MW / 464 MWh in California, Texas, New Jersey and Ohio.

In addition, we have an approximate 3GW/10GWh pipeline of potential projects, in different stages of development across the United States that will support our target to reach an energy storage portfolio of 352MW by the end of 2024 and between 500MW and 530MW by 2025. The development of such projects is dependent, inter alia, on site permitting, interconnection agreement, supply of Lithium- Ion batteries and economic viability, which are not certain. We plan to continue leveraging our experience in project development and finance, our engineering, procurement and construction know-how and our relationships with utilities and other market participants, to develop additional BESS projects.

### Business Strategy

Our business strategy reiterates and supports our position that climate change is among the most important issues of our time. A large part of our business involves bringing baseload energy to parts of the world that lack access to affordable renewable energy. Our Company recognizes the importance of the fight against climate change and the imperative of lowering global greenhouse gas emissions, and our core business actively works to counteract these existential threats. We are focused on helping to create a sustainable energy infrastructure, and further an alternative energy future, where greenhouse gas emissions are significantly reduced and the ability to access and store renewable sourced power will enable electricity grids to become more responsive, more stable, and more environmentally friendly.

Our goals include continuing our leading position in the geothermal energy market and becoming a leading global provider of renewable energy. Our strategy focuses on three main elements:

- Developing our renewable geothermal business in the United States and globally;
- Establishing a strong market position in the IFM energy storage market; and
- Exploring opportunities in new areas by looking for synergistic growth opportunities utilizing our core competencies, strong market reputation, and new market opportunities focused upon environmental solutions.

We intend to implement this strategy through:

- *Development and Construction of New Geothermal Power Plants -* seeking out commercially viable renewable geothermal resources, to accelerate the development and construction of new zero emission geothermal power plants by entering into long-term PPAs providing stable and sustainable cash flows.
- *Expanding our Geographical Reach —* increasing our business development activities in an effort to grow our business in the global markets in all business segments. While we continue to evaluate global opportunities, we currently see the United States, Indonesia, Central America and Greece as attractive markets for our Electricity Segment. We see New Zealand, Philippines, Turkey, Chile, Indonesia, keep in United States and China as attractive markets for our Product Segment. We are actively looking at ways to expand our presence in these countries to offer and provide replacement to carbon-intensive power alternatives.
- *Accelerating the Development and Construction of New Energy Storage Assets -* increasing our business development activities seeking potential sites for development and construction of energy storage facilities (including hybrid storage and solar PV facilities) in an effort to significantly grow our energy storage market and provide efficient solutions to the grid.
- *Acquisition of New Geothermal Assets -* expanding and accelerating growth through acquisition activities globally, aiming to acquire additional geothermal assets as well as operating and development assets that can support our geothermal business.
- *Acquisition of Energy Storage Projects and Assets –* expanding and accelerating growth through acquisition activities of operating assets, shovel ready projects and projects in various stages of development.
- *Using Our Operational Capabilities to Increase Output from our Existing Geothermal Power Plants -* increasing output from our existing geothermal power plants by adding additional generating capacity, upgrading plant technology, and improving geothermal reservoir operations, including improving methods of heat source supply and delivery.
- *Creating Cost Savings Through Increased Operating Efficiency -* increasing efficiencies in our operating power plants and manufacturing facility including procurement by adding new technologies, restructuring of management control, automating part of our manufacturing work and centralizing our operating power plants.
- *Diversifying our Customer Base -* evaluating a number of strategies for expanding our customer base to the CCA's markets. In the near term, however, we expect that the substantial majority of our revenues will continue to be generated from our traditional electrical utility customer base for the Electricity segment.
- *Maintaining a Prudent and Flexible Capital Structure -* we have various financing structures in place, including non-recourse project financings, green convertible bonds, the sale of differential membership interests and equity interests in certain subsidiaries, as well as revolving credit facilities and term loans. We believe our cash flow profile, the long-term nature of our contracts, and our ability to raise capital provide greater flexibility for optimizing our capital structure.
- *Improving our Technological Capabilities —* investing in research and development of renewable energy technologies and leveraging our technological expertise to continuously improve power plant components, reduce operations and maintenance costs, develop competitive, eco-efficient and low-carbon products for electricity generation and target new service opportunities. In addition, we are expanding our core geothermal competencies to provide high efficiency solutions for high enthalpy applications by utilizing our binary enhanced cycle and technology.
- *Manufacturing and Providing Products and EPC Services Related to Renewable Energy -* designing, manufacturing and contracting power plants for our own use and selling to third parties power units and other generation equipment for geothermal and recovered energy-based electricity generation.
- *Expanding into New Technologies -* leveraging our technological capabilities over a variety of renewable energy platforms, including solar power generation, energy storage and recovered energy generation. We may acquire companies with integration and technological capabilities that we do not currently have, or develop new technology ourselves, where we can effectively leverage our expertise to implement this part of our strategic plan.

The map below shows our worldwide portfolio of operating geothermal, solar PV and recovered energy power plants as of February 22, 2023.

We believe our activities as a provider of renewable energy and our continued investment in clean and renewable assets help reduce greenhouse gas emissions .

\* In the Sarulla complex, we include our 12.75% share only.

The map below shows our portfolio of operating storage facilities as of February 22, 2023.

### Sustainability Strategy

We are committed to engaging with stakeholders on, and strengthening our commitment to, sustainability issues, including environmental, social and governance (“ESG”) matters. We endorse external initiatives and partner with national and international associations that we believe assist us in meeting our ESG commitments and values, in particular, relating to geothermal, energy and health and safety issues. We strive to provide recent, credible and comparable data to ESG agencies while engaging institutional investors and investor advocacy organizations around ESG issues.

As a renewable energy solution provider, we are motivated to identify opportunities and risks with respect to climate change and take efforts to reduce our greenhouse gas (“GHG”) emissions and improve our energy efficiency. In addition to meeting our regulatory requirements, we report our annual GHG emissions to global organizations, including CDP and the Israeli Ministry of Environmental Protection’s voluntary business reporting initiative.

We report our progress on environmental goals and commitments annually in our Sustainability Reports, including, but not limited to, our climate change mitigation measures, biodiversity conservation, and water management efforts. A copy of our most recent Sustainability Report is accessible, free-of-charge, on our website at https://investor.ormat.com/sustainability-report. The contents of our website, including the Sustainability Reports, are not part of or otherwise incorporated by reference into this Form 10-K.

### Our Proprietary Technology

Our proprietary technology involves original designs of turbines, pumps, and heat exchangers, as well as formulation of organic motive fluids (all of which are non-ozone-depleting substances) and may be used either in power plants operating according to the ORC alone or in combination with various other commonly used thermodynamic technologies that convert heat to mechanical power, such as gas and steam turbines. It can be used with a variety of thermal energy sources, such as geothermal, recovered energy, biomass, solar energy and fossil fuels. By using advanced computational fluid dynamics techniques and other computer aided design software as well as our test facilities, we continuously seek to improve power plant components, reduce operations and maintenance costs, and increase the range of our equipment and applications. We examine ways to increase the output of our plants by utilizing evaporative cooling, cold reinjection, configuration optimization, and topping turbines.

We also developed, patented and constructed GCCU power plants in which the steam first produces power in a backpressure steam turbine and is subsequently condensed in a vaporizer of a binary plant, which produces additional power. Our Geothermal Combined Cycle technology is depicted in the diagram below.

In the conversion of geothermal energy into electricity, our technology has a number of advantages over conventional geothermal steam turbine plants. A conventional geothermal steam turbine plant consumes significant quantities of water, causing depletion of the aquifer and requiring cooling water treatment with chemicals and consequently a need for the disposal of such chemicals. A conventional geothermal steam turbine plant also creates a significant visual impact in the form of an emitted plume from the cooling towers, especially during cold weather. By contrast, our binary and combined cycle geothermal power plants have a low profile with minimal visual impact and do not emit a plume when they use air-cooled condensers. Our binary and combined cycle geothermal power plants reinject all of the geothermal fluids utilized in the respective processes into the geothermal reservoir. Consequently, such processes generally have no emissions.

Other advantages of our technology include simplicity of operation and maintenance and higher yearly availability. For instance, the OEC employs a low speed and high efficiency organic vapor turbine directly coupled to the generator, eliminating the need for reduction gear. In addition, with our binary design, there is no contact between the turbine blade and geothermal fluids, which can often be very erosive and corrosive. Instead, the geothermal fluids pass through a heat exchanger, which is less susceptible to erosion and can adapt much better to corrosive fluids. In addition, with the organic vapor condensed above atmospheric pressure, no vacuum system is required.

We use the same elements of our technology in our recovered energy products. The heat source may be exhaust gases from a Brayton cycle gas turbine, low-pressure steam, or medium temperature liquid found in the process industries such as oil refining and cement manufacturing. In most cases, we attach an additional heat exchanger in which we circulate thermal oil or water to transfer the heat into the OEC’s own vaporizer in order to provide greater operational flexibility and control. Once this stage of each recovery is completed, the rest of the operation is identical to that of the OECs used in our geothermal power plants and enjoys the same advantages of using the ORC. In addition, our technology allows for better load following than conventional steam turbines, requires no water treatment (since it is air cooled and organic fluid motivated), and does not require the continuous presence of a licensed steam boiler operator on site.

Our REG technology is depicted in the diagram below.

### Patents

As of December 31, 2022, we have 225 patents and patent applications worldwide, including 63 patents issued in the US and 35 pending U.S. patent applications. These patents and patent applications cover our products (mainly power units based on the ORC) and systems (mainly geothermal power plants and industrial waste heat recovery plants for electricity production). The product-related patents cover components that include turbines, heat exchangers, air coolers, seals and controls as well as control of operation of geothermal production well pumps. The system-related patents cover not only particular components but also the overall energy conversion system from the “fuel supply” (e.g., geothermal fluid, waste heat, biomass or solar) to electricity production.

The system-related patents also cover subjects such as waste heat recovery related to gas pipeline compressors and industrial waste heat, solar power systems, disposal of non-condensable gases present in geothermal fluids, reinjection of other geothermal fluids ensuring geothermal resource sustainability, power plants for very high-pressure geothermal resources, two-phase fluids, low temperature geothermal brine as well as processes related to EGS. Fifty-five of our patents cover combined cycle geothermal power plants, in which the steam first produces power in a backpressure steam turbine and is subsequently condensed in a vaporizer of a binary plant, which produces additional power. The remaining terms of our issued patents range from one year to 16 years. The loss of any single patent would not have a material effect on our business or results of operations.

### Research and Development

We conduct research and development activities intended to improve plant performance, reduce costs, and increase the breadth of our product offerings. The primary focus of our research and development efforts is targeting power plant conceptual thermodynamic cycle and major equipment including continued performance, cost and land usage improvements to our condensing equipment, and development of new higher efficiency and higher power output turbines and brine production pumps. New realms for innovation include implementation of predictive maintenance software and automation of power plants performance analysis.

We also devote resources to research and development related to our energy storage segment. Our engineering and R&D teams are working to optimize the dispatch strategy of a battery energy storage system (BESS), develop and deploy capabilities to self-integrate BESS and test different battery cell and inverter technologies under simulated operating criteria of various energy markets to allow us to bring to market cost-effective BESS more rapidly and more optimized to the specific use cases and target revenue streams. Additionally, we hold patents in other energy storage solutions and continue to evaluate investment opportunities in companies with innovative technology or product offerings for renewable energy and energy storage solutions.

### Market Opportunities

### Geothermal Market Opportunities

Renewable energy provides a sustainable alternative to the existing solutions to two major global issues: climate change and volatile commodity costs. Renewable energy solutions are sustainable, clean and decarbonizes the grid. These environmental benefits have led numerous countries to focus their efforts on the development of renewable energy sources in general and geothermal specifically.

Based on data provided by ThinkGeo Energy in January 2023, the total installed geothermal power generation capacity at year-end 2022 stood at 16,128 MW, an increase of 274 MW over 2021. The leading countries with installed geothermal power generation are the U.S., Indonesia, the Philippines, Turkey, Mexico and New Zealand. The largest growth in 2022 happened in Indonesia and the U.S., which had an addition of 152 MW.

Realizing the importance of renewable energy alternatives, including geothermal alternatives providing firm baseload non-weather-dependent resource, various governments have instituted or have been preparing regulatory frameworks and policies to achieve emission reduction targets, and provide incentives to develop the sector and maximize renewable energy resources, create jobs, and improve energy reliability.

### United States

Interest in geothermal energy in the United States continues to grow based on supportive legislation and regulation at the local, state, and federal levels. Policy makers and regulators are becoming increasingly aware of the comparatively high value of geothermal energy in contrast to intermittent renewable technology, as seen through individual state’s renewable portfolio standard (RPS) goals (as described below) accounting for more baseload energy than ever before as coal, natural gas and nuclear power plants reach retirement.

Today, electricity generation from geothermal resources is concentrated primarily in California, Nevada, Hawaii, Idaho, Oregon, and Utah, and we believe there are opportunities for geothermal expansion in other states such as New Mexico and Colorado. New Mexico recently passed legislation increasing its renewable energy goals to 100% by 2045 for investor-owned utilities and Colorado is introducing new tax incentives for geothermal development.

On August 16, 2022, the Inflation Reduction Act of 2022 ("IRA") was signed, which is effective for taxable years beginning after December 31, 2022. The IRA includes several tax incentives to promote climate change mitigation and clean energy, electric vehicles, battery and energy storage manufacture or purchase. Some highlights of the IRA include production tax credits (“PTCs”) or investment tax credits (“ITCs”) for wind and solar projects (including geothermal and hydropower) beginning construction before January 1, 2025. The PTCs and ITCs, as amended by the IRA, will apply to facilities placed in service after December 31, 2022. We expect the IRA will enable us to enter into tax equity transactions and fund a higher percentage of our investment. This should reduce our capital needs and increase the project economics. We expect that our geothermal projects starting operation in next five to six years should be eligible for these credits.

Geothermal energy provides numerous benefits to the U.S. grid and economy. Geothermal development and operation bring economic benefits in the form of tax incentives and long term high-paying jobs, and it currently has one of the lowest LCOE of all power sources in the United States, according to the U.S. Energy Information Administration - EIA - Independent Statistics and Analysis report published in February 2019. Additionally, improvements in geothermal production make it possible to provide ancillary and on-demand services. This helps load serving entities avoid additional costs from purchasing and then balancing intermittent resources with storage or new transmission.

#### State level legislation

Many state governments have enacted an RPS program under which utilities are required to include renewable energy sources as part of their energy generation portfolio. Under an RPS, participating states have set targets to produce their energy from renewable sources with specific deadlines. Renewable energy generation under an RPS program is tracked through the production of RECs. Load serving entities track the RECs to ensure they are meeting the mandate prescribed by the RPS.

Currently in the United States, 42 states plus the District of Colombia and four territories have enacted an RPS, renewable portfolio goals, or similar laws or incentives (such as clean energy standards or goals) requiring or encouraging load serving entities in such states to generate or buy a certain percentage of their electricity from renewable energy or recovered heat sources. The vast majority of Ormat’s geothermal projects are in California, Nevada, and Hawaii which have some of the most stringent RPS programs in the country. We see the impact of RPS and climate legislation as a significant driver for us to expand existing power plants and to build new renewable projects.

States also provide incentives to geothermal energy producers. Nevada provides a property tax abatement of up to 55% for real and tangible personal property used to generate electricity from geothermal sources. The abatement may extend up to twenty years if certain job creation requirements are met. In Idaho, geothermal energy producers are exempt from property tax and, in lieu, pay a tax of 3% of gross energy earnings. The California Energy Commission provides favorable grants and loans to promote the development of new or existing geothermal resources and technologies within the state. Also in California, the CPUC has required Electric Load Service Entities (LSEs) to procure 11.5 GW of new clean electricity by 2028, 1 GW of this procurement must deliver firm power with an 80% capacity factor, produce zero on-site emissions, and be weather independent. With a high capacity factor and firm and flexible generation, geothermal energy addresses these requirements and is the natural replacement for baseload fossil fuels and nuclear generation.

In 2022, Ormat announced two additional PPAs for up to 160 MW of geothermal energy with Nevada Energy, and another power purchase agreement for up to 125 MW portfolio of geothermal projects with California Community Power.

### Global

We believe the global markets continue to present growth and expansion opportunities in both established and emerging markets.

We believe several global Climate Change initiatives are likely to create business expansion opportunities for us and support the global growth of the renewable sector, such as the Paris Agreement approved by the Twenty-first Conference of the Parties to the UN Framework Convention on Climate Change (2015) and subsequent UN Climate Change Conferences which reaffirmed the commitments of the Paris Agreement.

Outside of the United States, the majority of power generating capacity has historically been owned and controlled by governments. Since the early 1990s, however, many foreign governments have privatized their power generation industries through sales to third parties encouraging new capacity development and/or refurbishment of existing assets by independent power developers. These foreign governments have taken a variety of approaches to encourage the development of competitive power markets, including awarding long-term contracts for energy and capacity to independent power generators and creating competitive wholesale markets for selling and trading energy, capacity, and related products. Some foreign regions and countries have also adopted active government programs designed to encourage clean renewable energy power generation such as the following countries in which we operate, sell products and/or are conducting business development activities:

#### Europe

Europe has the fourth largest geothermal power capacity, the majority of which stems from Italy and Turkey and recently small scale projects in Germany. A significant part of our European operations is in Turkey. We are looking for opportunities to expand in Europe, primarily in our Product segment.

A significant part of our European operations is in Turkey, and since 2004, we have established strong business relationships in the Turkish geothermal market and provided our wide range of solutions including our binary systems, to over 40 geothermal power plants with a total capacity of approximately 900 MW. We believe the potential for geothermal growth in Turkey is still high, specifically in center-south and east areas of the country, however, due to the ongoing economic crisis in Turkey, new projects and investments are at a standstill.

#### Latin America

Several Latin American countries have renewable energy programs and have pursued development in the geothermal market.

In Guatemala, where our Zunil and Amatitlan power plants are located, the government approved and adopted the Energy Policy 2013-2027 that secures, among other things, a supply of electricity at competitive prices by diversifying the energy mix with an 80% renewable energy share target for 2027.

In Honduras, where we operate our Platanares power plant, the government set a target to reach at least 80% renewable energy production by 2034.

#### New Zealand

In New Zealand, where we have been actively providing geothermal power plant solutions since 1988, the government’s policies to fight climate change include a net zero GHG emissions reduction target by 2050 and a renewable electricity generation target of 90% of New Zealand’s total electricity generation by 2035. We continue selling power plants and products to our New Zealand customers and cooperate with other potential customers for adding geothermal power generation capacity within the coming years. In 2022, we signed an EPC contract to build the 59MW Tehuka 3 geothermal project. We are currently exploring an opportunity to build and own a power plant in New Zealand.

#### Asia

The Electricity Law of 2009 (in conjunction with Job Creation Act No. 11 of 2020/Omnibus Law) is the principal regulation for the electricity industry in Indonesia which divides the industry into two broad categories: (1) electrical power provision, covering electric power generation, transmission, distribution and sales and (2) electrical power support such as services (consulting, construction, installation, operation & maintenance, certification & training, testing etc.) and manufacture (tools, power plant equipment, cables, electrical equipment, etc.). The electrical power provision business is dominated by PLN (a state-owned enterprise), which is the sole owner of transmission and distribution assets and 70% of the power generation assets. Private sector participation in power generation is allowed through an IPP scheme, mostly done through tenders or direct appointment for some power sources such as geothermal. Geothermal power is regulated by The Geothermal Law issued in 2014 (as also amended by the Indonesian Omnibus Law in 2020), that endorses private participation as a geothermal IPP. The central government conducts tenders for geothermal fields, awarding a Geothermal Business License for the winner. Geothermal Business License holders can conduct exploration and feasibility studies within five years and subject to two times one-year extensions, conduct well development and power plant construction and sell the electricity generated to PLN for a maximum of 30 years. Prior to the expiration of the Geothermal License, the IPP can propose to extend the license for an additional 20 years. In 2021, Presidential Regulation No. 112 was enacted with the aim of accelerating Renewable Energy. This regulation replaces the basis of the renewable energy tariff from the average electricity generation basic cost to a ceiling price. In this scheme, the tariff is negotiated between IPP and PLN and must not be higher than the ceiling tariff set for particular type of renewable energy power plant, which is then multiplied by a factor based on location.

#### East Africa

In East Africa the geothermal potential along the Rift Valley is estimated at several thousand MW. The countries along the Rift Valley are at different stages of development of their respective geothermal potential.

In Kenya, there are already several geothermal power plants, including our 150 MW Olkaria III complex. The Kenyan government has identified the country's untapped geothermal potential as the most suitable indigenous source of electricity.

The Kenyan government is aiming to reach 10 GW of power generating capacity by 2037, pursuant to the Least-Cost Power Development Plan 2017-37, which had a target of 62% of such capacity generated from renewable energy sources (including large hydro and solar).

### Energy Storage

In the U.S., the IRA provides direct incentives to our Energy Storage segment by making projects eligible for ITCs. We also expect to see our Energy Storage segment benefit from the incentives available to other renewable energy technologies, which we believe will increase the need for energy storage.

In Europe, impacts from the war in Ukraine increased the demand for renewable energy. The IEA estimates, in its 2022 Renewable Analysis and Forecast, that global renewable energy deployment between 2022-2027 will be 2,400GW, which represents an increase of 85% over the previous five years. This increase can place strain on the electric grid as adding intermittent renewables such as wind and solar can create situations where a significant amount of capacity must be available to ramp up and down to accommodate these resource’s daily output cycles and variations due to weather conditions. Furthermore, the output from wind and solar PV power plants can change significantly over short periods of time due to environmental conditions like cloud movement and fog burn off and can cause instability on the electric grid. As a result, we believe that energy storage is positioned to become a key component of the grid to provide flexibility and reliability.

Energy storage systems utilize surplus, available electricity that enables utilities and grid operators to optimize the operation of the grid, run generators closer to full capacity for longer periods, and operate the grid more efficiently and effectively. As penetration of wind and solar resources increases, so does the need for services that energy storage systems can provide to “balance the grid”, such as local capacity, frequency regulation, ramping, reactive power, black start and movement of energy from times of excess supply to times of high demand. Common applications for energy storage systems include ancillary services, wind/solar smoothing, energy trading, peaker replacement, and transmission and distribution deferral.

According to Wood Mackenzie's Energy Storage Monitor for Q4 2022, approximately 1.3 GW/4.7 GWh of new grid-scale energy storage projects were installed in the United States as of Q3 2022 and this number represents a 26%/48% increase compared to Q3 2021. Wood Mackenzie is forecasting that annual energy storage deployments will grow to 65GWh by 2026, of which 84% is expected to be grid-scale installations (vs. community, commercial and industrial as well as residential installations, which are expected to comprise 16% of total installations).

BESS deployment in the United States saw record growth in 2022, and significant growth in BESS deployment is expected to continue primarily for grid-connected (also referred to as “in front of the meter”) applications. Many power systems across the U.S. are facing significant challenges such as: grid aging; grid congestion; retirement of aging thermal generators; implementation of greenhouse gas emission reduction targets; and the increasing penetration of intermittent renewable energy resources, all of which drive the further deployment of grid-scale energy storage.

Recently the industry has experienced, and it is still facing, challenges in the development of new energy storage projects due to global supply chain constraints and inflation, which has caused an increase in prices and a shortage of core components of energy storage projects, specifically batteries. Our projects under development have experienced delays as a result of these challenges as well as challenges related to interconnection.

We own and operate several grid-scale BESS facilities, where revenues are derived from selling energy, capacity and/or ancillary services in merchant markets like PJM Interconnect, ISO New England, the ERCOT and the CAISO. We are pursuing the development of additional grid-connected BESS projects in multiple regions, with expected revenues coming from providing energy, capacity and/or ancillary services on a merchant basis, or through bilateral contracts with load serving entities, e.g. investor owned utilities, publicly owned utilities and community choice aggregators. We are also pursuing the development of storage plus Solar PV facilities.

#### Solar PV

The solar PV market continues to grow, and is benefited by the IRA as well as the general desire to replace conventional generation with renewable resources. We are monitoring market drivers with the potential to develop solar PV power plants in locations where we can offer competitively priced power generation. Our current focus is in adding solar PV systems in some of our operating geothermal power plants to reduce internal consumption loads, as well as developing solar PV and BESS projects in targeted regions where economics are favorable. Since 2019, we successfully placed in service one 20MW stand-alone Solar PV project an additional 17MW of solar PV augmentation systems adjacent to operating geothermal power plants in Nevada. We are also currently constructing and developing similar projects totaling 43MW.

### Other Opportunities

#### Recovered Energy Generation

In addition to our geothermal power generation activities, we are pursuing recovered energy-based power generation opportunities in the United States and worldwide. We believe recovered energy-based power generation will ultimately benefit from the efforts to reduce GHG emissions. We have built 23 power plants in North America which generate electricity utilizing “waste heat” from gas turbine-driven compressor stations along interstate natural gas pipelines, from midstream and gas processing facilities, and from other applications.

The passage of the IRA extended ITCs of up to 30% for waste energy projects in the United States. As such, several states, and the federal government, have recognized the environmental benefits of recovered energy-based power generation.

EU aims to become the world’s first climate-neutral continent by 2050 and reduce greenhouse gas emissions by 55% (compared to 1990 levels) by 2030. A main element in decarbonization is the energy sector, by aiming to increase the share of renewables in The overallenergy mix and meet to enhanced energy efficiency targets via integrated energy systems.

We believe that these policies, incentives, and ambitious targets are likely to encourage the development of renewable energy technologies, including waste heat recovery, throughout U.S. and Europe. We believe that other markets worldwide may offer similar opportunities in recovered energy-based power generation.

In summary, the market for the recovery of waste heat converted into electricity exists either when already available electricity is expensive or where the regulatory environment facilitates construction and marketing of power generated from recovered waste heat. However, such projects tend to be smaller than 9 MW and we expect any growth to be relatively slow and geographically scattered.

### Operations of our Electricity Segment

### How We Own Our Power Plants

We customarily establish a separate subsidiary to own interests in each of our power plants. This ensures that the power plant, and the revenues generated by it, will be the only source for repaying indebtedness, if any, incurred to finance the construction or the acquisition (or to refinance the construction or acquisition) of the relevant power plant. If we do not own all of the interest in a power plant, we enter into a shareholders’ agreement or a partnership agreement that governs the management of the specific subsidiary and our relationship with our partner in connection with the specific power plant. Our ability to transfer or sell our interests in certain power plants may be restricted by certain purchase options or rights of first refusal in favor of our power plant partners or the power plant’s power purchasers and/or certain change of control and assignment restrictions in the underlying power plant and financing documents. All of our domestic geothermal and REG power plants are Qualifying Facilities under the PURPA and are eligible for regulatory exemptions from most provisions of the FPA and certain state laws and regulations.

### How We Explore and Evaluate Geothermal Resources

We conduct exploration activities globally. It generally takes two to three years from the time we start active exploration of a particular geothermal resource to the time we have resource confirmation through drilling and testing. This timeframe assumes the resource is commercially viable and there is an intention to pursue its development. Exploration activities generally involve the phases described below.

#### Initial Evaluation

We identify and evaluate potential geothermal resources through field investigations using a robust geoscience program identified through both public and private data sources.

Our initial evaluation is usually conducted by our internal exploration team, although we might engage outside service providers for some tasks from time to time. The costs associated with an initial evaluation vary from site to site, based on various factors, including the acreage involved and the costs, if any, of obtaining information from private databases or other sources. On average, our expenses for an initial evaluation range from approximately $10,000 (mainly in the U.S.) to $50,000 (mainly in the international prospects) including travel, chemical analyses, and data acquisition.

If we conclude, based on the information considered in the initial evaluation, that the geothermal resource has potential to support a commercially viable power plant,considering various factors described below, we proceed to land rights acquisition.

#### Land Acquisition

We acquire land rights to any geothermal resources our initial evaluation indicates could potentially support a commercially viable power plant. For domestic power plants, we either lease or own the sites on which our power plants are located. For our foreign power plants, our lease rights for the power plant site are generally contained in the terms of a concession agreement or other contract with the host government or an agency thereof. In certain cases, we also enter into one or more geothermal resource leases (or subleases), a concession, an option agreement or other agreement granting us the exclusive right to extract geothermal resources from specified areas of land, with the owners (or sublessors) of such land.

For most of our current exploration sites in the United States, we acquire rights to use the geothermal resource through land leases with the BLM (which regulates leasehold interests in U.S. federal land), with various states, or through private leases. A summary of our typical lease terms is provided below under “Description of our Leases and Lands”. The up-front bonus and royalty payments vary from site to site and are based on, among other things, current market conditions.

#### Surveys

We conduct geological, geochemical, and/or geophysical surveys on the sites we acquire. These surveys are conducted incrementally considering relative impact and cost, and the geologic model is updated from time to time.

We make a further determination of the commercial viability of the geothermal resource based on the results of this process, particularly the results of the geochemical surveys estimating temperature and the overall geologic model, including potential resource size. If the results from the geochemical surveys are poor (i.e., low derived resource temperatures or poor permeability) or the geologic model indicates small or deep resource, we re-evaluate the commercial viability of the geothermal resource and may not proceed to exploratory drilling. We generally only move forward with those sites that we believe have a high probability of successful development.

#### Exploratory Drilling

We drill one or more exploratory wells on the high priority, relatively low risk sites to confirm and/or define the geothermal resource. Each year we determine and approve an exploration budget for the entire exploration activity in such year. We prioritize budget allocation between the various geothermal sites based on commercial and geological factors. The costs we incur for exploratory drilling vary from site to site based on various factors, including the accessibility of the drill site, the geology of the site, and the depth of the resource. However, on average, exploration costs, prior to drilling of a full-size well are approximately $1.0 million to $3.0 million for each site, not including land acquisition and depending on the success we see in the early stages of exploration. Outside the U.S. exploration costs can be higher.

At various points during our exploration activities, we re-assess whether the geothermal resource involved will support a commercially viable power plant based on information available at that time. For example, once we have a successful exploration wells, we then test the resource for up to several months to study long-term viability with temporary surface equipment. Well testing data informs the resource numerical model and supports decisions such as power plant capacity and specifications.

If we conclude that a geothermal resource will support a commercially viable power plant, we move to the phase of constructing a power plant at the site. Additional wells may be drilled during the plant construction phase to meet the design point criteria.

### How We Construct Our Power Plants.

The principal phases involved in constructing one of our geothermal power plants are as follows:

- *Drilling production and injection wells.* We consider completing the drilling of the first production well to be the beginning of our construction phase for a power plant. However, this is not always sufficient for a full release of a project for construction. The number of production wells varies from plant to plant depending on, among other things, the geothermal resource, the projected capacity of the power plant, the power generation equipment to be used and the way geothermal fluids will be re-injected through injection wells to maintain the geothermal resource and surface conditions. We generally drill the wells ourselves although in some cases we use outside contractors. The cost for each production and injection well varies depending on, among other things, the depth and size of the well and market conditions affecting the supply and demand for drilling equipment, labor and operators. In the last five years, our typical cost for each production and injection well ranged between $1.3 million to $13.3 million. An average cost for a domestic well was approximately $3.6 million and $7.6 million for international wells.
- *Designing the well field, power plant, equipment, controls, and transmission facilities.* We usually use our own employees to design the well field and the power plant, including equipment that we manufacture and that will be needed for the power plant. In some cases, depending on complexity and location, we use third parties to help us with the design. The designs vary based on various factors, including local laws, required permits, the geothermal resource, the expected capacity of the power plant and the way geothermal fluids will be re-injected to maintain the geothermal resource and surface conditions.
- *Obtaining any required permits, electrical interconnection and transmission agreements.* We use our own employees and from time to time, depending on complexity and location, outside consultants to obtain any required permits and licenses for our power plants that are not already covered by the terms of our site leases. The permits and licenses required vary from site to site and are described below under “Environmental Permits”.
- *Manufacturing (or in the case of equipment we do not manufacture ourselves, purchasing) the equipment required for the power plant.* Generally, we manufacture most of the power generating unit equipment we use at our power plants. Multiple sources of supply are typically available for all other equipment we do not manufacture.
- *Assembling and constructing the well field, power plant, transmission facilities, and related facilities.* We use our own employees to manage construction work.The construction and installation works (such as site grading, civil, structural, mechanical, insulation, electrical, control and communication works) are normally subcontracted. Construction materials (such as concrete, rebar etc.), construction equipment (cranes, forklifts etc.) and tools are provided by us to the subcontractors in some cases or provided by the subcontractors.

In recent years, it has taken approximately two to three years from the time we drill a production well until a power plant becomes operational. During 2022, in the Electricity segment, we focused on the commencement of operations at Tungsten Mountain enhancement in Nevada, CD4 power plant and Heber-2 Repowering in California, Zunil upgrade in Guatemala and Olkaria optimization in Kenya. In addition, we commenced operations at Wister solar in California as well as at Tungsten Solar and Steamboat Solar in Nevada. We also focused on construction of Heber-1 repower, The North Valley power plant as well as with enhancement work in some other of our operating power plants worldwide. We also commenced construction of the Dixie Valley upgrade and some Solar PV projects to supply power to the auxiliary loads of our power plants.

When deciding whether to continue holding lease rights and/or to pursue exploration activity, we diligently prioritize our prospective investments, taking into account resource and probability assessments in order to make informed decisions about whether a particular project will support commercial operation.

We may conclude that a prospective geothermal resource will not support commercial operations. In such case, costs associated with exploration activities will be expensed accordingly under the Write-off of Unsuccessful Exploration Activities line item in the consolidated statements of operations in our financial statements.

### How We Operate and Maintain Our Power Plants

Our operations and maintenance practices are designed to minimize operating costs without compromising safety or environmental standards while maximizing plant flexibility and maintaining high reliability. Our operations and maintenance practices for geothermal power plants seek to preserve the sustainable characteristics of the geothermal resources we use to produce electricity and maintain steady-state operations within the constraints of those resources reflected in our relevant geologic and hydrologic studies. Our approach to plant management emphasizes the operational autonomy of our individual plant or complex managers and staff to identify and resolve operations and maintenance issues at their respective power plants; however, each power plant or complex draws upon our available collective resources and experience, and that of our subsidiaries. We have organized our operations such that inventories, maintenance, backup, and other operational functions are pooled within each power plant complex and provided by one operation and maintenance provider. This approach enables us to realize cost savings and enhances our ability to meet our power plant availability goals.

Safety is a key area of concern to us. We believe that the most efficient and profitable performance of our power plants can only be accomplished within a safe working environment for our employees. Our compensation and incentive program includes safety as a factor in evaluating our employees, and we have a well-developed reporting system to track safety and environmental incidents, if any, at our power plants.

### How We Sell Electricity

In the United States, our purchasers are typically investor-owned electric utility companies or electric cooperatives including public owned utilities, and more recently, CCAs. Outside of the United States, our purchasers are either state-owned utilities or privately-owned-entities. We typically operate our facilities under rights granted to us by a governmental agency pursuant to a concession agreement. In each case, we enter into long-term contracts (typically, PPAs) for the sale of electricity or the conversion of geothermal resources into electricity. Although previously our power plants’ revenues under a PPA generally consisted of two payments, energy payments and capacity payments, our recent PPAs provide for energy payments only. Energy payments are normally based on a power plant’s electrical output actually delivered to the purchaser measured in kWh, with payment rates either fixed or indexed to the power purchaser’s “avoided” power costs (i.e., the costs the power purchaser would have incurred itself had it produced the power it is purchasing from third parties) or rates that escalate at a predetermined percentage each year. Capacity payments are normally calculated based on the generating capacity or the declared capacity of a power plant available for delivery to the purchaser, regardless of the amount of electrical output actually produced or delivered. In addition, we have one domestic power plants located in Hawaii that is eligible for capacity payments under the respective PPAs upon reaching certain levels of generation, or subject to a capacity payment reduction if certain levels of generation are not reached.

### How We Finance Our Power Plants

Historically we have funded our power plants with different sources of liquidity such as a non-recourse or limited recourse debt, lease financing, tax monetization transactions, internally generated cash, which includes funds from operations, as well as proceeds from loans under corporate credit facilities, green convertibles corporate bonds public debt and equity offerings, senior unsecured corporate bonds, project financing and the sale of equity interests and other securities. Our debt financing permits the development of power plants with a limited amount of equity contributions, but also increases the risk that a reduction in cashflow could adversely affect a particular power plant’s ability to meet its debt obligations. Leveraged financing also means that distributions of dividends or other distributions by our subsidiaries to us are contingent on compliance with financial and other covenants contained in the applicable finance documents.

In 2022, we raised several corporate and project finance loans and expanded and renewed our revolving credit facilities to support our geothermal and storage growth.

We have used financing structures to monetize PTCs and depreciation, such as our tax equity partnership transaction involving McGinness Hills Phase 3, Tungsten and Steamboat Hills Repowering Project and in 2022 the CD4 power plant. Our Dixie Valley power plant, acquired from Terra-Gen in 2021, has a leveraged lease financing arrangement.

### How We Mitigate International Political Risk.

We generally, but not always, purchase insurance policies to cover our portion of our book equity exposure to certain political risks involved in operating in developing countries, as described below under “Insurance”. However, insurance may not cover all political risks or coverage amounts may not be sufficient.

### Description of Our Leases and Lands

We have domestic leases on approximately 381,746 acres of federal, state, and private land in California, Hawaii, Nevada, New Mexico, Utah, Idaho and Oregon. The approximate breakdown between federal, state and private leases and owned land is as follows:

- 78% of the acreage under our control is leased from the U.S. government, mainly through the BLM;
- 18% is leased or subleased from private landowners and/or leaseholders;
- 2% is owned by us; and
- 2% is leased from various states.

Each lease has standard terms and requirements, as summarized below. Internationally, our land position includes approximately 59,154 acres.

### BLM Geothermal Leases

Certain of our domestic project subsidiaries have entered into geothermal resource leases with the U.S. government, pursuant to which they have obtained the right to conduct their geothermal development and operations on federally-owned land. These leases are made pursuant to the Geothermal Steam Act. The lessor under such leases is the U.S. government, acting through the BLM.

BLM geothermal leases grant the geothermal lessee the right and privilege to drill for, extract, produce, remove, utilize, sell, and dispose of geothermal resources on certain lands, together with the right to build and maintain necessary improvements thereon. The actual ownership of the geothermal resources and other minerals beneath the land is retained in the federal mineral estate. The geothermal lease does not grant to the geothermal lessee the exclusive right to develop the lands, although the geothermal lessee does hold the exclusive right to develop geothermal resources within the lands. Since BLM leases do not grant to the geothermal lessee the exclusive right to use the surface of the land, BLM may grant rights to others for activities that do not unreasonably interfere with the geothermal lessee’s uses of the same land, including use, off-road vehicles, and/or wind or solar energy developments.

Typical BLM leases issued to geothermal lessees before August 8, 2005 have a primary term of ten years and will renew so long as geothermal resources are being produced or utilized in commercial quantities but cannot exceed a period of forty years after the end of the primary term. If at the end of the forty-year period geothermal steam is still being produced or utilized in commercial quantities and the lands are not needed for other purposes, the geothermal lessee will have a preferential right to renew the lease for a second forty-year term, under terms and conditions as the BLM deems appropriate.

BLM leases issued after August 8, 2005 have a primary term of ten years. If the geothermal lessee does not reach commercial production within the primary term, the BLM may grant two five-year extensions. If the lessee is drilling a well for the purposes of commercial production, the lease may be extended for five years and thereafter, as long as steam is being produced and used in commercial quantities, the lease may be extended for up to thirty-five years. If, at the end of the extended thirty-five-year term, geothermal steam is still being produced or utilized in commercial quantities and the lands are not needed for other purposes, the geothermal lessee will have a preferential right to renew the lease under terms and conditions as the BLM deems appropriate.

For BLM leases issued before August 8, 2005, the geothermal lessee is required to pay an annual rental fee (on a per acre basis), which escalates according to a schedule described therein, until production of geothermal steam in commercial quantities has commenced. After such production has commenced, the geothermal lessee is required to pay royalties (on a monthly basis) on the amount or value of (i) steam, (ii) by-products derived from production, and (iii) commercially de-mineralized water sold or utilized by the project (or reasonably susceptible to such sale or use).

For BLM leases issued after August 8, 2005, (i) a geothermal lessee who has obtained a lease through a non-competitive bidding process will pay an annual rental fee equal to $1.00 per acre for the first ten years and $5.00 per acre each year thereafter; and (ii) a geothermal lessee who has obtained a lease through a competitive process will pay a rental equal to $2.00 per acre for the first year, $3.00 per acre for the second through tenth year and $5.00 per acre each year thereafter. Rental fees paid before the first day of the year for which the rental is owed will be credited towards royalty payments for that year. For BLM leases issued, effective, or pending on August 5, 2005 or thereafter, royalty rates are fixed between 1.0-2.5% of the gross proceeds from the sale of electricity during the first ten years of production under the lease. The royalty rate set by the BLM for geothermal resources produced for the commercial generation of electricity but not sold in an arm’s length transaction is 1.75% for the first ten years of production and 3.5% thereafter. The royalty rate for geothermal resources sold by the geothermal lessee or an affiliate in an arm’s length transaction is 10.0% of the gross proceeds from the arm’s length sale.

In the event of a default under any BLM lease, or the failure to comply with any of the provisions of the Geothermal Steam Act or regulations issued under the Geothermal Steam Act or the terms or stipulations of the lease, the BLM may, 30 days after notice of default is provided to the relevant project, (i) suspend operations until the requested action is taken, or (ii) cancel the lease.

### Private Geothermal Leases

Certain of our domestic project subsidiaries have entered into geothermal resources leases with private parties, pursuant to which they have obtained the right to conduct their geothermal development and operations on privately owned land. In many cases, the lessor under these private geothermal leases owns only the geothermal resource and not the surface of the land.

Typically, the leases grant our project subsidiaries the exclusive right and privilege to drill for, produce, extract, take and remove from the leased land water, brine, steam, steam power, minerals (other than oil), salts, chemicals, gases (other than gases associated with oil), and other products produced or extracted by such project subsidiary. The project subsidiaries are also granted certain non-exclusive rights pertaining to the construction and operation of plants, structures, and facilities on the leased land. Additionally, the project subsidiaries are granted the right to dispose geothermal fluid as well as the right to re-inject into the leased land water, brine, steam, and gases in a well or wells for the purpose of maintaining or restoring pressure in the productive zones beneath the leased land or other land in the vicinity. Because the private geothermal leases do not grant to the lessee the exclusive right to use the surface of the land, the lessor reserves the right to conduct other activities on the leased land in a manner that does not unreasonably interfere with the geothermal lessee’s uses of the same land, which other activities may include agricultural use (farming or grazing), recreational use and hunting, and/or wind or solar energy developments.

The leases provide for a term consisting of a primary term in the range of five to 30 years, depending on the lease, and so long thereafter as lease products are being produced or the project subsidiary is engaged in drilling, extraction, processing, or reworking operations on the leased land.

As consideration under most of our project subsidiaries’ private leases, the project subsidiary must pay to the lessor a certain specified percentage of the value “at the well” (which is not attributable to the enhanced value of electricity generation), gross proceeds, or gross revenues of all lease products produced, saved, and sold on a monthly basis. In certain of our project subsidiaries’ private leases, royalties payable to the lessor by the project subsidiary are based on the gross revenues received by the lessee from the sale or use of the geothermal substances, either from electricity production or the value of the geothermal resource “at the well”.

In addition, pursuant to the leases, the project subsidiary typically agrees to commence drilling, extraction or processing operations on the leased land within the primary term, and to conduct such operations with reasonable diligence until lease products have been found, extracted and processed in quantities deemed “paying quantities” by the project subsidiary, or until further operations would, in such project subsidiary’s judgment, be unprofitable or impracticable. The project subsidiary has the right at any time within the primary term to terminate the lease and surrender the relevant land. If the project subsidiary has not commenced any such operations on said land (or on the unit area, if the lease has been unitized), or terminated the lease within the primary term, the project subsidiary must pay to the lessor, in order to maintain its lease position, annually in advance, a rental fee until operations are commenced on the leased land.

If the project subsidiary fails to pay any installment of royalty or rental when due and if such default continues for a period of fifteen days specified in the lease, for example, after its receipt of written notice thereof from the lessor, then at the option of the lessor, the lease will terminate as to the portion or portions thereof as to which the project subsidiary is in default. If the project subsidiary defaults in the performance of any obligations under the lease, other than a payment default, and if, for a period of 90 days after written notice is given to it by the lessor of such default, the project subsidiary fails to commence and thereafter diligently and in good faith take remedial measures to remedy such default, the lessor may terminate the lease.

We do not regard any property that we lease as material unless and until we begin construction of a power plant on the property.

### Description of Our Power Plants

### Domestic Operating Power Plants

The following descriptions summarize certain industry metrics for our domestic operating power plants:

### Power plants in the United States

| Project Name | Size (MW) | Technology | Resource Cooling | Customer | PPA Expiration |
| --- | ---: | --- | --- | --- | --- |
| Brawley | 7 | Geothermal water-cooled binary system | Depends on the mix of used production wells , with current decline rate around 2°F per year | SCE | 2031 |
| Brady Complex | 26 | Geothermal air and water-cooled binary system | Brady and Desert Peak 2 - less than 3°F per year | NV Energy | Brady — 2022 Desert Peak 2 — 2027 |
| Don A. Campbell Complex (1)(2) | 32 | Geothermal air cooled binary system | 4°F to 5°F per year | SCPPA | Phase 1 - 2034 Phase 2 - 2036 |
| Heber Complex (3) | 81 | Geothermal dual flash and binary systems using a water cooled system | 1°F to 2°per year | SCPPA and Peninsula Clean Energy (PCE) | Heber 1 — 2025 Heber 2 — 2037(4) Heber South — 2031 |
| Jersey Valley | 8 | Geothermal air cooled binary system | Under 2°F per year | Nevada Power Company | 2032 |
| Mammoth Complex | 65 | Geothermal air cooled binary system | About 1°F per year | PG&E and Southern California Edison. | G-1 and G-3 - 2034 G-2 plant - 2027 |
| McGinness Hills Complex | 146(14) | Geothermal air cooled binary system | About 5°F per year | Nevada Power Company and SCPPA. | Phases 1 and 2 - 2033 Phase 3 - 2043. |
| Neal Hot Springs (5) | 24 | Geothermal air cooled binary system | 1.5°F over the past year | Idaho Power Company | 2038 |
| OREG 1 (2) | 22 | Geothermal air cooled binary system | NA | Basin Electric Power Cooperative | 2031 |
| OREG 2 (2) | 22 | Geothermal air cooled binary system | NA | Basin Electric Power Cooperative | 2034 |

31

|  |  |  |  |  |  |
| --- | ---: | --- | --- | --- | --- |
| OREG 3 (2) | 5.5 | Geothermal air cooled binary system | NA | Great River Energy. | 2029 |
| OREG 4 | 3.5 | Geothermal air cooled binary system | NA | Highline Electric Association. | 2029 |
| Ormesa Complex | 36 | Geothermal water-cooled binary system and water-cooled flash system. | Less than 1.5°F per year | SCPPA under a single PPA. | 2042 |
| Puna Complex (2),(6) | 38 | Geothermal combined cycle and air cooled binary system | The resource temperature is stable | HELCO | 2027 |
| Raft River | 12 | Geothermal water-cooled binary system | The resource temperature is stable | Idaho Power Company. | 2032 |
| San Emidio | 11 | Geothermal- water-cooled binary system | 1°F per year | NV Energy. | 2038 |
| Steamboat Complex | 79 | Geothermal air and water-cooled binary system and a single flash system | Lower Steamboat - between 2°F to 3°F per year Steamboat Hills 4°F per year | \* Steamboat 2 & 3- Sierra Pacific Power Company \* Galena1 & 3- Nevada Power Company \* Galena 2 & Steamboat Hills- SCPPA | Steamboat 2 and 3- 2022 Galena1- 2026 Steamboat Hills and Galena 2 - 2043 Galena 3- 2028 |
| Steamboat Solar | 5 | Solar PV System | NA | Internal use (11) | NA |
| Tungsten Mountain Geothermal | 42 | Geothermal air and water-cooled binary system | About 3°F per year | SCPPA | 2043 |
| Tungsten Mountain solar | 12 | Solar PV System | NA | Internal use (11) | NA |
| Tuscarora | 18 | Geothermal water-cooled binary system | Temperature decline has continued to lessen, currently under 2.5°F per year | Nevada Power Company. | 2032 |
| Dixie Valley | 58 | Geothermal air-cooled binary system and water-cooled flash system. | The resource temperature is stable | SCE | 2038 |
| Beowawe | 14 | Flash System and Binary | 1°F per year | NV Energy | 2025 |
| Wister | 20 | Solar PV System | NA | San Diego Gas & Electric | 2042 |

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### Foreign Power plants

| Project Name | Size (MW) | Technology | Resource Cooling | Customer | PPA Expiration |
| --- | ---: | --- | --- | --- | --- |
| Amatitlan (Guatemala) | 20 | Geothermal air cooled binary system and a small back pressure steam turbine (one MW) | Declining at about 2°F per year | INDE and another local purchaser. | 2028 |
| Bouillante (France)(7) | 15 | Geothermal direct steam turbines. | The resource temperature is stable | EDF pursuant to a PPA. | 2030 |
| Olkaria III Complex (Kenya)(8) | 150 | Geothermal air cooled binary system | Declining at about 2°F per year | KPLC | Plant 2 - 2033 Plant 1&3 - 2034 Plant 4 - 2036 |
| Platanares (Honduras) (9) | 38 | Geothermal air cooled binary system | Decline rate has increased and is at 6°F per year | ENEE | 2047 |
| Sarulla Complex - (Indonesia) (10) | 330 (our share is 42) | Geothermal Combined Cycle steam and binary systems | NIL power plant is declining at about 3°F per year and SIL is decling at about 1°F per year | PLN | 2047 |
| Zunil (Guatemala) | 20 | Geothermal air cooled binary system | The resource temperature is stable | INDE | 2034 |

(1) Don A. Campbell is experiencing cooling since mid-2016, with 4°F to 5°F in the last year, which is reducing its generating capacity. Injection tests and tracer studies, along with reservoir modeling have been used to develop a plan to mitigate temperature decline of the reservoir. Temperature mitigation program is ongoing.

(2) 36.75% indirectly owned by Northleaf.

(3) We completed the enhancement of the Heber 2 power plant and currently working to replace the Heber 1 old steam turbine that was damaged in the fire and caused a shutdown of Heber 1.

(4) A new 15-year contract was signed for Heber 2 with PCE.

(5) 40% owned by Enbridge Inc. Upgrades to the power plant were completed in 2020.

(6) On May 3, 2018, the Kilauea volcano located in close proximity to our Puna 38 MW geothermal power plant in the Puna district of Hawaii's Big Island erupted following a significant increase in seismic activity in the area. The Puna power plant resumed operations in November 2020 and during 2021 operated at a level of 23-25 MW. We continue with drilling and workovers into 2023 to increase generation. In 2019, we reached an agreement with HELCO and signed a new PPA, subject to final PUC approval. The new PPA extends the current until 2052 and increases the current contract capacity by 8 MW to 46MW. In addition, the new PPA has a fixed price with no escalation, regardless of changes to fossil fuel pricing, which impacts the majority of our current pricing under the existing PPA. We are currently negotiating economic amendments to the new PPA. The existing PPA remains in effect with its current terms until the earlier of a) PPA's expiration date at the end of 2027 and b) the new PPA will be in effect.

(7) 85% of the Bouillante power plant is jointly owned by Ormat and CDC, with 75% allocated to Ormat and 25% to CDC.

(8) The Olkaria complex experienced lower performance of the wellfield since 2021 and currently is generating 125 MW.

(9) We hold the Platanares assets, including the project’s wells, land, permits and a PPA, under a BOT structure for 15 years from the date the Platanares plant commenced commercial operation on September 26, 2017. A portion of the land on which the project is located is held by us through a lease from a local municipality.

(10) The Sarulla complex is experiencing a reduction in generation primarily due to wellfield issues at one of its power plants, as well as equipment failures which resulted in a decrease in profitability. During the second quarter of 2022, Sarulla agreed with its banks on a framework that will enable it to perform remediation work that is aimed to restore the plant’s performance, however, uncertainty remains regarding Sarulla’s ability to meet the plan and the Company is evaluating the impact of the plan on future performance. As we determined that the current situation and circumstances related to our equity method investment in Sarulla are temporary, no impairment testing was required for the period.

(11) The Tungsten and Steamboat Solar power plants generate energy that is used for the auxiliary power of the geothermal power plants

### Future Projects

### Projects Released for Construction

We have several projects in various stages of construction, including 11 projects that we have fully released for construction with a total capacity of 91MW and one project with capacity of 10MW to 15MW that is in the early stages of construction. In 2022, due to COVID-19 and other factors, we experienced delays in obtaining all relevant permits, delays in interconnection and delays in procuring panels for a Solar PV project, resulting in delays in expected COD.

These projects are expected to have a total geothermal generating capacity of between 62 MW (representing our interest) and solar PV projects with a total capacity of 29 MW

| Project Name | Location | Expected Size (MW) | Technology | Customer | Expected COD | Current Condition |
| --- | --- | ---: | --- | --- | --- | --- |
| Heber Complex | California, U.S. | 8 | Geothermal air-cooled binary system | SCE and SCPPA | Q2 2023 | Construction progressing |
| Dixie Meadows | Nevada, U.S. | 12 | Geothermal air-cooled binary system | SCPPA | On Hold | On hold. See further under Note 21 |
| North Valley | Nevada, U.S. | 25 | Geothermal air-cooled binary system | NV Energy | Q1 2023 | Plant Construction completed. Pre-Commissioning activities ongoing on site. T-line construction near completion |
| Dixie Valley upgrade | Nevada, U.S. | 6 | Geothermal air-cooled binary system | SCE | Q2 2023 | Near completion |

34

|  |  |  |  |  |  |  |
| --- | --- | ---: | --- | --- | --- | --- |
| Beowawe Repower | Nevada, U.S. | 6 | Geothermal air-cooled binary system |  | Q3 2024 |  |
| Zunil | Guatemala | 5 | Geothermal air-cooled binary system | INDE | H2 2023 | Construction near completion |
| Brady Solar | Nevada, U.S. | 6 | Solar PV System | Internal use | Q1 2023 | Construction ongoing. Equipment deliveries ongoing |
| Steamboat Solar Phase 2 | Nevada, U.S. | 7 | Solar PV System | Internal use | Q2 2023 | Construction commenced. Awaiting solar panels to arrive. |
| North Valley Solar | Nevada, U.S. | 6 | Solar PV System | Internal use | Q3 2023 | Engineering and procurement completed. Permitting ongoing |
| Steamboat Hills Solar Phase 2 | Nevada, U.S. | 4 | Solar PV System | Internal use | Q3 2023 | Engineering and procurement are ongoing |
| Beowawe Solar | Beowawe Solar | 6 | Solar PV System | Internal use | H1 2024 | Project released. Engineering and procurement are ongoing |
| Carson Lake | Nevada, U.S. | 10 - 15 | Geothermal air-cooled binary system | No PPA | TBD | Early stage of construction |

### Projects under Various Stages of Development that were not Released for Construction

We also have projects under various stages of development in the United States, Indonesia and Guadeloupe that we estimate will increase the generating capacity of our geothermal projects by approximately 43 MW (representing our interest) and a Solar PV project with a total of 14 MW. We expect to continue to explore these and other opportunities for expansion so long as they continue to meet our business objectives and investment criteria. However, we prioritize our investments based on their readiness for continued construction and expected economics and therefore we are not planning to invest in all of such projects in 2023.

| Project | Location | Technology | Size (MW) | Customer | Expected COD |
| --- | --- | --- | ---: | --- | --- |
| Bouillante power plant | Guadeloupe | Geothermal | 10 | Under discussion with EDF | H1 2025 |
| Puna Expansion | Hawaii, U.S. | Geothermal | 8 | HELCO | 2025 |
| Ijen | Indonesia | Geothermal | 15 (1) | PLN | Q4 2024 |
| North Valley 2 | Nevada, U.S. | Geothermal | 10 | TBD | 2026 |
| McGinness Solar | Nevada, U.S. | Solar PV | 14 | SCPPA | H2 2024 |

(1) The size of the project reflects Ormat's 49% interest share

### Future Prospects

We have a substantial land position that is expected to support future development and on which we have started or plan to start exploration activity. When deciding whether to continue holding lease rights and/or to pursue exploration activity, we diligently prioritize our prospective investments, taking into account resource and probability assessments in order to make informed decisions about whether a particular project will support commercial operation.

Our current land position is comprised of various leases, concessions and private land for geothermal resources of approximately 205,000 acres in **39** prospects across the western United States, Latin America, Africa and New Zealand. In the United States we hold **28** prospects:

- 20 prospects in Nevada
- 3 prospects in California
- 2 in Oregon
- 2 in Utah
- 1 in New Mexico

Outside the U.S. we hold **11** prospects:

- 2 prospects in Indonesia
- 4 prospects Ethiopia
- 2 prospects in Guatemala
- 1 prospect in Honduras
- 1 prospect in New Zealand.
- 1 prospect in Madagascar.

### Operations of our Product Segment

### Power Units for Geothermal Power Plants

We design, manufacture, and sell power units for geothermal electricity generation, which we refer to as OECs. Our customers include contractors and geothermal plant owners and operators.

The power units are usually paid for in installments, in accordance with milestones set forth in the supply agreement. We also provide the purchaser with spare parts (either upon their request or our recommendation). We provide the purchaser with at least a 12-month warranty for such products. We provide the purchaser with performance guarantees (usually in the form of standby letters of credit), which partially terminates upon delivery of the equipment to the site and terminates in full at the end of the warranty period.

### Power Units for Recovered Energy-Based Power Generation

We design, manufacture, and sell power units used to generate electricity from recovered energy or so-called “waste heat”. Our existing and target customers include interstate natural gas pipeline owners and operators, gas processing plant owners and operators, cement plant owners and operators, biomass facilities owners and operators and all other companies engaged in energy-intensive industrial processes such as glass, steel and other. We manufacture and sell the power units for recovered energy-based power generation to third parties for use in “inside-the-fence” installations or otherwise.

### EPC of Power Plants

We engineer, procure and construct, as an EPC contractor, geothermal and recovered energy power plants on a turnkey basis, using power units we design and manufacture. Our customers are geothermal power plant owners as well as our target customers for the sale of our recovered-energy based power units described above. Unlike many other companies that provide EPC services, we believe that our advantage is in using our own manufactured equipment and thus have better quality and control over the timing and delivery of equipment and related costs. The consideration for such services is usually paid in installments, in accordance with milestones set forth in the EPC contract and related documents. We provide performance guarantees securing our obligations under the contract.

In connection with the sale of our power units for geothermal power plants, power units for recovered energy-based power generation, we enter into agreements, from time to time, with sales representatives for the marketing and sale of such products pursuant to which we are obligated to pay commissions to such representatives upon the sale of our products in the relevant territory.

Our manufacturing operations and products are certified ISO 9001, ISO 14001, American Society of Mechanical Engineers (ASME), Pressure Equipment Directive and TÜV, and we are an approved supplier to many electric utilities around the world.

### Backlog

We have a product backlog of approximately $148.1 million as of February 22, 2023, which includes revenues for the period between January 1, 2023 and February 22, 2023, compared to $53.5 million as of February 16, 2022, which included revenues for the period between January 1, 2022 and February 16, 2022. The increase in the 2023 backlog is mainly related to the continued recovery following COVID-19 related impacts, and the signing of a new large EPC contract in New Zealand during 2022 and a supply contract in Indonesia for the Ijen project..

The following is a breakdown of the Product segment backlog amount (in $ millions) by countries as of February 22, 2023:

| Country | Backlog Amount | Percentage of Backlog |
| --- | ---: | ---: |
| New Zealand | 73.8 | 49.8% |
| Guatemala | 8.1 | 5.5% |
| Philippines | 11.0 | 7.4% |
| U.S. | 4.8 | 3.2% |
| Indonesia | 36.7 | 24.8% |
| Taiwan | 3.1 | 2.1% |
| Israel | 3.8 | 2.6% |
| Germany | 2.8 | 1.9% |
| Others | 4.0 | 2.7% |
| Total | 148.1 | 100% |

The following is a breakdown of the Product segment backlog by technology as of February 22, 2023:

|  | % of Total Backlog | Latest Expected Completion |
| --- | ---: | --- |
| Geothermal | 94.7% | 2024 |
| Recovered Energy | 2.7% | 2023 |
| Pumps | 2.1% | 2025 |
| Other | 0.5% | 2023 |

### Operations of our Energy Storage Segment

### Storage Projects

In addition to our Geothermal activity, we own, operate and develop energy storage projects in the United States including the following:

### Under operation

| Project Name | Customer | Location | Size (MW) | MWh | Type of contract |
| --- | --- | --- | ---: | ---: | --- |
| ACUA | PJM | NJ | 1 | 1 | Merchant |
| Plumsted | PJM | NJ | 20 | 20 | Merchant |
| Stryker | PJM | NJ | 20 | 20 | Merchant |
| Hinesburg | ISONE | VT | 2.0 | 5.0 | Merchant |
| Rabbit Hill | ERCOT | TX | 10.0 | 10.0 | Merchant |
| Pomona | SCE/CAISO | CA | 20.0 | 80.0 | Capacity PPA and Merchant |
| Vallecito | CAISO and SCE | CA | 10.0 | 40.0 | Capacity PPA and Merchant |
| Tierra Buena | CAISO, RCEA and VCE | CA | 5.0 | 20.0 | Capacity PPA and Merchant |
| **Total** |  |  | **88.0** | **196.0** |  |

37

### Under construction and development

| Project Name | Customer | Location | Size (MW) | MWh | Type of contract | Expected COD |
| --- | --- | --- | ---: | ---: | --- | --- |
| Upton | ERCOT | TX | 25 | 25 | Merchant | Q1 2023 |
| Andover | PJM | NJ | 20 | 20 | Merchant | Q1 2023 |
| Howell | PJM | NJ | 7 | 7 | Merchant | Q1 2023 |
| Bowling Green | PJM | OH | 12 | 12 | Capacity and Merchant | Q1 2023 |
| Pomona 2 | SCE/CAISO | CA | 20 | 40 | Capacity and Merchant | Q3 2023 |
| Bottleneck | CAISO | CA | 80 | 320 | Tolling | Q1 2024 |
| East Flemington | PJM | NJ | 20 | 20 | Merchant | Q3 2023 |
| Montague | PJM | NJ | 20 | 20 | Merchant | Q4 2024 |
| **Total** |  |  | **204.0** | **464.0** |  |  |

### Energy Storage Pipeline

For an energy storage prospect to move into the EPC phase, it requires site control, an executed interconnection agreement, permits from all authorities and a viable financial model. We have a substantial pipeline of approximately 2.9GW/9.9GWh of projects in different stages of development for future development in the United States that will support our target to reach an energy storage portfolio of 352MW by the end of 2024 and between 500MW and 530MW by 2025.

### Competition

### Electricity Segment

In our Electricity segment, we face competition from geothermal power plant owners and developers as well as other renewable energy providers and developers.

Competition in the Electricity segment occurs in the very early stage of development and in advanced stages when obtaining a PPA. The early stage is primarily obtaining the rights to the resource for development of future projects or acquiring a site already in a more advanced stage of development. From time to time and in different jurisdictions competing geothermal developers become our customers in the Product segment.

Our main competitors in the geothermal sector in the United States are CalEnergy, Calpine Corporation, Enel Green Power S.p.A., Cyrq Energy Inc. and other smaller pure play developers. Outside the United States, in many cases our competitors are companies that are gaining experience developing geothermal projects in their own countries such as Mercury and Contact Energy in New Zealand, Energy Development Corporation from the Philippines, Storenergy and Meridian from France and Enel Green Power from Italy. In Indonesia we experience competition on land from Kaishan, PT Pertamina Geothermal Energy and PT Star Energy and in a recent tender Chevron teamed with Pertimina to compete with us for land. In Japan, Japanese company, Impex, is active in the geothermal space, but we have not experienced any competition yet. Some Turkish developers are also focusing on the international market. Additionally, we face competition from country-specific companies and smaller pure play geothermal developers.

In obtaining new PPAs, we also face competition from companies engaged in the power generation business from other renewable energy sources, such as wind power, biomass, solar power and hydroelectric power. In the United States we primarily compete against solar power generation combined with energy storage. We also face competition from existing geothermal power plants as they are re-contracted.

As a geothermal company, we are focused on niche markets where our baseload and flexibility advantages can allow us to develop competitive projects.

### Product Segment

In our Product segment, we face competition from power plant equipment manufacturers and system integrators as well as engineering or project management companies.

Our competitors among power plant equipment suppliers are divided by technology, steam turbines and binary power plant manufacturers. Our main steam turbine competitors are industrial steam turbine manufacturers such as Mitsubishi Heavy Industries, Fuji Electric Co., Ltd. and Toshiba Corporation of Japan, GE/Nuovo Pignone and Ansaldo Energia of Italy.

Our binary technology competitors are manufacturers using the ORC technology such as Mitsubishi Heavy Industries through Turboden, TICA, a Chinese air conditioning company that acquired Italian Exergy, Egesim, a Turkish electrical contractor who is collaborating with Atlas Copco mainly in the Turkish market and internationally, Kaishan, a compressor manufacturer from China who also develops its own projects and Fuji Electric Co., Ltd of Japan. While we believe that we have a distinct competitive advantage based on our accumulated experience, an increase in competition, which we are currently experiencing, has started to affect our ability to secure new purchase orders from potential customers. The increased competition in addition to increase in raw material costs led to a reduction in the operating margins, which in turn impacted our profitability.

In the REG business, our competitors are other ORC manufacturers, mainly Mitsubishi/Turboden and TICA/Exergy, which dominate binary waste heat recovery market installations. Other manufacturers are conventional steam turbines and small scale ORC suppliers.

In the case of proposed EPC projects we also compete with other service suppliers, such as project/engineering companies or EPC contractors.

### Energy Storage Segment

In the Energy Storage segment, we face significant competition from companies that have already established businesses in the sector, companies that are seeking to acquire established businesses to gain a foothold in the sector, and new market entrants.

The energy storage space is comprised of many companies with different business strategies, such as independent power producers, project developers, system integrators, EPC contractors, component suppliers (e.g. batteries, inverters, control software, and balance of plant), and scheduling coordinators, among others. The energy storage space is experiencing consolidation; however, the number of IPPs in the market remains high and competition is intense.

We continue to develop greenfield projects with great emphasis on the quality of the location and other characteristics that will make for highly profitable projects as well as targeting strategic acquisitions of development assets or platforms. Additionally, we believe that our participation and expertise in various parts of the value chain, such as engineering, procurement, construction, project development, operation and maintenance, and asset management and market participation puts us at a competitive advantage in the market of utility scale energy storage.

### Customers

All of our revenues from the sale of Electricity in the year ended December 31, 2022 were derived from fully-contracted energy and/or capacity payments under long-term PPAs with governmental, public or private utility entities. The percentage of total revenues above 5% is detailed in the table below:

| Utility | % of total revenues for the year ended December 31, 2022 |
| --- | ---: |
| SCPPA (U.S.) | 21.5% |
| NV Energy (U.S.) | 16.9% |
| KPLC (Kenya) | 14.4% |

39

Based on publicly available information, as of December 31, 2022, the credit ratings of our rated electric utility customers are as set forth below:

|  |  |  |
| --- | --- | --- |
| **Issuer** | Standard & Poor’s Ratings Services | Moody’s Investors Service Inc. |
| **Southern California Edison** | BBB (Stable) | Baa2 (Stable) |
| **HELCO** | BBB- (Stable) | Ratings withdrawn |
| **Sierra Pacific Power Company** | A (Stable) | Baa1 (Stable) |
| **Nevada Power Company** | A (Stable) | Baa1 (Stable) |
| **SCPPA** | BBB+ (Stable) | (Stable) |
| **PG&E** | BB- (Stable) | Ba2 (Stable) |
| **EDF** | BBB+ (Stable) | Baa (Negative) |

The credit ratings of any power purchaser may change from time to time. There is no publicly available information with respect to the credit rating or stability of the power purchasers under the PPAs for our foreign power plants other than EDF (France).

Our revenues from the Product segment are derived from contractors, owners, or operators of power plants, process companies, and pipelines.

Our revenues from the Energy Storage segment are derived from selling energy, capacity services under long term capacity contracts and/or ancillary services in merchant markets like PJM, ISO New England, ERCOT and CAISO. We recently signed a long-term tolling agreement we believe that will secure fixed revenues for our Bottleneck 80MW/320MWh project in California. In addition, we are pursuing projects that will serve entities, such as investor owned utilities, publicly owned utilities and community choice aggregators.

### Human Capital Resources

### Our Team

As a global renewable energy company, we are proud to employ and work closely with the communities we serve, knowing we contribute to local economies and social well-being. The promise of renewable energy that we deliver to our customers and stakeholders goes hand in hand with our commitment to local employment and skill development wherever we work.

Our success largely depends on our ability to recruit, develop and retain a productive and engaged workforce. Accordingly, investing in our employees, focusing on safety, offering competitive compensation and benefits, promoting a diverse workforce, adopting forward thinking human capital management practices and community outreach are critical elements of our corporate strategy.

As of December 31, 2022, we employed 1,480 employees, of whom 523 were in Israel, 706 were in the United States, and 251 were in other countries. Any future material growth in our employee headcount will be attributable to purchasing or developing new power plants and energy storage facilities.

### Workforce Health and Safety

The health and safety of our employees, subcontractors, the public, and the environment is our overarching priority. We manage risks by identifying, assessing and managing risks in the facilities and offices that we own and operate. In addition, we promote safety awareness and values. Our goal is to report, analyze, learn and improve performance to reduce the number of incidents. We seek to continuously improve our safety performance and instill a workplace safety culture. We also periodically conduct quality, environmental, health, and safety audits of our plants and facilities.

Ormat has an Integrated Quality, Environment, Health, and Safety Policy ("QEHS") that sets out our general commitments towards health and safety principles at our sites and for all our stakeholders. The policy is publicly available on Ormat's website and outlines our responsibilities to provide high quality products, conduct our business with care for the environment, and integrate our QEHS system into our business strategy and work processes. In addition, our Human Rights and Labor Policy, also available publicly on our website, outlines our commitments to ensuring that essential health and safety standards and practices are enforced in the workplace, developing risk awareness, and encouraging responsible health and safety behavior among employees.

In addition, we have an outreach plan to support communities where we do business such as addressing the reduced availability of food to vulnerable populations and providing medical and personal protective equipment to local healthcare workers across the globe.

### Diversity Initiatives

We strive to provide a diverse and inclusive working environment where people are respected and feel a sense of belonging regardless of race, nationality, gender, age, religion or sexual orientation. Our offices, manufacturing plants and power plants are in multiple jurisdictions and our global workforce operates across many different beliefs. We are committed to local employment at all our operational and manufacturing locations. While our first and foremost consideration of a potential candidate is professional skills and overall qualifications for the position, we work with several organizations in the U.S. to help us present opportunities to ethnic minorities and veterans for open positions. Furthermore, we are committed to eliminating discrimination in our hiring and employment termination practices and ensuring that all employees are adequately accommodated and treated equally.

We actively seek opportunities to hire and promote female employees and managers across our Company, including our various operations worldwide.

### Competitive Compensation and Benefits

We strive to ensure that all eligible employees receive fair and competitive compensation and benefits, including, paid maternity or paternity leave, sponsorship of learning opportunities, health care insurance, short-term and long-term disability, among others. Our global employees are entitled to retirement and pension benefits at or beyond the legally required level of employer contribution in the relevant country of operation, including access to 401(k) plans in the U.S. We fully cover retirement and pension plan liabilities in relevant countries of operation with our available resources. In addition, all our current employees in Israel are entitled to benefits in the event of termination or retirement following the Israeli Government’s sponsorship of programs that provide limited non-pension benefits.

### Employee Investment

We focus on creating opportunities for employee education, development and training and we strive to ensure that employees are fulfilling their professional and personal goals. Our training opportunities include professional and soft skills to help our employees improve their performance and expand their horizons. We have annual performance reviews for most of our employees. Our Human Resources department and various business units work together on initiatives to create a sense of community and togetherness. We offer employees options to improve their work-life balance, including community events, holiday and team milestone celebrations, volunteering opportunities and fitness support.

### Collective Bargaining Agreements & Employee Unions

As of December 31, 2022, the only employees represented by a labor union are the employees of our acquired Bouillante power plant located in Guadeloupe. The employees in Guadeloupe are represented by the Confédération Générale du Travail de Guadeloupe. We maintain good relations with our employees and have not encountered any labor relations issues such as labor disputes, strikes, or work stoppages. We seek to continue to maximize a positive work environment for all our employees. .

We have no collective bargaining agreements for our Israeli employees. However, by order of the Israeli Ministry of Economy and Industry, the provisions of a collective bargaining agreement between the Histadrut (the General Federation of Labor in Israel) and the Coordination Bureau of Economic Organizations (which includes the Industrialists Association) may apply to some of our Israeli non-managerial, finance and administrative, and sales and marketing personnel. This collective bargaining agreement principally concerns the cost of living pay increases, length of the workday, minimum wages and insurance for work-related accidents, annual and other vacation, sick pay, and determination of severance pay, pension contributions, and other conditions of employment. We currently provide such employees with benefits and working conditions, at least as favorable as the conditions specified in the collective bargaining agreement.

### Insurance

We maintain physical damage and business interruption insurance, including the perils of flood, volcanic eruption, earthquake and windstorm, cyber coverage, general and excess liability, pollution legal liability, control of well, drilling rigs, construction risks, as well as customary worker’s compensation and automobile, marine transportation insurance and such other commercially available insurance as is generally carried by companies engaged in similar businesses and owning similar properties in the same general areas as us. Such insurance covering our properties extends to Ormat and/or our owned, controlled, direct or indirect affiliated or associated companies, subsidiary companies or corporations in amounts generally based upon the estimated replacement value and maximum foreseeable loss of our facilities (provided that certain perils including earthquake, volcanic eruption and flood coverage are subject to sublimit and/or annual aggregate limits depending on the type and location of the facility) and business interruption insurance coverage in an amount that also varies from location to location.

We purchase certain insurance policies to cover a portion of our book equity investment to specified political risks involved in operating in developing countries. We hold a global political risk insurance program covering the significant political risks at certain of our locations. This program is issued by the global insurers in the private sector. Such insurance policies generally cover, subject to the limitations and restrictions contained therein, losses derived from a specified governmental act, such as expropriation, political violence, and the inability to convert local currency into hard currency and, in certain cases, the breach of agreements with governmental entities, in approximately 70% of our book net equity investment.

### Regulation of the Electric Utility Industry in the United States

The following is a summary overview of the electric utility industry and applicable federal and state regulations and should not be considered a full statement of the law or all issues pertaining thereto.

### PURPA

PURPA and FERC's regulations thereunder exempt owners of small power production Qualifying Facilities that use geothermal resources as their primary source and other Qualifying Facilities that are 30 MW or under in size from regulation under the PUHCA 2005, from many provisions of the FPA and from state laws relating to the financial, organization and rate regulation of electric utilities.

PURPA provides the owners of power plants certain benefits described below if a power plant is a “Qualifying Facility.” A small power production facility is a Qualifying Facility if: (i) the facility does not exceed 80 MW; (ii) the primary energy source of the facility is biomass, waste, geothermal, or renewable resources, or any combination thereof, and at least 75% of the total energy input of the facility is from these sources, and fossil fuel input is limited to specified uses; and (iii) the facility, if larger than one megawatt, has filed with FERC a notice of self-certification of qualifying status, or has been certified as a Qualifying Facility by FERC. The 80 MW size limitation, however, does not apply to a facility if (i) it produces electric energy solely by the use, as a primary energy input, of solar, wind, waste or geothermal resources; and (ii) an application for certification or a notice of self-certification of qualifying status of the facility was submitted to not later than December 31, 1994, and construction of the facility commenced not later than December 31, 1999.

With respect to the FPA, FERC's regulations under PURPA do not exempt from the rate provisions of the FPA sales of energy or capacity from Qualifying Facilities larger than 20 MW in size that are made (a) pursuant to a contract executed after March 17, 2006 or (b) not pursuant to a state regulatory authority’s implementation of PURPA. The practical effect of these regulations is to require owners of Qualifying Facilities that are larger than 20 MW in size to obtain market-based rate authority from FERC if they seek to sell energy or capacity other than pursuant to a contract executed on or before March 17, 2006 or pursuant to a state regulatory authority’s implementation of PURPA. A sale to a public utility under PURPA at state approved avoided cost rates is generally exempt from FERC rate regulation.

In addition, provided that the purchasing electric utility has not been relieved from its mandatory purchase obligation, PURPA and FERC’s regulations under PURPA obligate electric utilities to purchase energy and capacity from Qualifying Facilities at either the electric utility’s avoided cost or a negotiated rate. FERC's regulations under PURPA allow FERC, upon request of a utility, to terminate a utility’s obligation to purchase energy from Qualifying Facilities upon a finding that Qualifying Facilities have nondiscriminatory access to: (i) independently administered, auction-based day ahead, and real time markets for electric energy and wholesale markets for long-term sales of capacity and electric energy; (ii) transmission and interconnection services provided by a FERC-approved regional transmission entity and administered under an open-access transmission tariff that affords nondiscriminatory treatment to all customers, and competitive wholesale markets that provide a meaningful opportunity to sell capacity, including long-term and short-term sales, and electric energy, including long-term, short-term, and real-time sales, to buyers other than the utility to which the Qualifying Facility is interconnected; or (iii) wholesale markets for the sale of capacity and electric energy that are at a minimum of comparable competitive quality as markets described in (i) and (ii) above. FERC regulations protect a Qualifying Facility’s rights under any contract or obligation involving purchases or sales that are entered into before FERC has determined that the contracting utility is entitled to relief from the mandatory purchase obligation. FERC has granted the request of California investor-owned utilities for a waiver of the mandatory purchase obligation for Qualifying Facilities larger than 20 MW in size. In addition, FERC recently amended its PURPA regulations to reduce the rebuttable presumption that small power production facilities in organized markets have nondiscriminatory access to markets from 20 MW to 5 MW. Therefore, the California investor-owned utilities may have a basis to further reduce their mandatory purchase obligation.

We expect that our power plants in the U.S will continue to meet all criteria required for Qualifying Facility status under PURPA. However, if any of our domestic power plants were to lose its Qualifying Facility status, such power plant could become subject to the full scope of the FPA and applicable state regulation. The application of the FPA and other applicable state regulation to our domestic power plants could require our operations to comply with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility.

### PUHCA

Under PUHCA 2005, the books and records of a utility holding company, its affiliates, associate companies, and subsidiaries are subject to FERC and state commission review with respect to transactions that are subject to the jurisdiction of either FERC or the state commission or costs incurred by a jurisdictional utility in the same holding company system. However, if a company is a utility holding company solely with respect to Qualifying Facilities, exempt wholesale generators, or foreign utility companies, it will not be subject to review of books and records by FERC under PUHCA 2005. Qualifying Facilities or exempt wholesale generators that make only wholesale sales of electricity are not subject to state commissions’ rate regulations and, therefore, in all likelihood would not be subject to any review of their books and records by state commissions pursuant to PUHCA 2005 as long as the Qualifying Facility is not part of a holding company system that includes a utility subject to regulation in that state. Additionally, most of our storage projects have exempt wholesale generator status, exempting them from PUHCA requirements as well.

### FPA

Pursuant to the FPA, FERC has exclusive jurisdiction over the rates for most wholesale sales of electricity and transmission of electricity in interstate commerce. These rates may be based on a cost of service approach or may be determined on a market basis through competitive bidding or negotiation. FERC can accept, reject or suspend rates. The rates can be suspended for up to five months, at which point the rates become effective subject to refund. FERC can order refunds for rates that are found to be “unjust and unreasonable” or “unduly discriminatory or preferential.”

Moreover, the loss of the Qualifying Facility status of any of our power plants might also permit the off-taker, pursuant to the terms of its PPA, to cease taking and paying for electricity from the relevant power plant and to seek refunds for past amounts paid and/or a reduction in future payments.

Additionally, FERC possesses civil penalty authority, up to approximately $1.3 million per violation of the FPA per day. FERC can also require the disgorgement of unjust profits earned in connection with such violations of the FPA and revoke the right of the power plants to make sales at market-based rates.

Under the Energy Policy Act of 2005, the FPA was supplemented to empower FERC to ensure the reliability of the bulk electric system. Such authority required that FERC assume both oversight and enforcement roles. Pursuant to its new directive, FERC certified the North American Electric Reliability Corporation as the nation’s Electric Reliability Organization (ERO) to develop and enforce mandatory reliability standards to address medium and long-term reliability concerns. Today, enforcement of the mandatory reliability standards, including the protection of critical energy infrastructure, is a substantial function of the ERO and of FERC, which may impose penalties of up to approximately $1.3 million a day for violating mandatory reliability standards. We examine our projects’ compliance with NERC standards on an ongoing basis and begin work on the process of NERC registration as new projects approach the threshold at which NERC standards become applicable.

Thus, if any of the power plants were to lose Qualifying Facility status, the application of the FPA and other applicable state regulations to such power plants could require compliance with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility. Even if a power plant does not lose Qualifying Facility status, the owner of a Qualifying Facility/power plant in excess of 20 MW will become subject to rate regulation under the FPA for sales of energy or capacity pursuant to a contract executed after March 17, 2006 or not pursuant to a state regulatory authority’s implementation of PURPA. A decrease in existing rates or being ordered by FERC to pay refunds for rates found to be “unjust and unreasonable” or “unduly discriminatory or preferential” would likely result in a decrease in our future revenues.

### State Regulation

Our power plants in California, Nevada, Oregon, and Idaho, by virtue of being Qualifying Facilities that make only wholesale sales of electricity, are not subject to rate, financial and organizational regulations applicable to electric utilities in those states. The power plants each sell or will sell their electrical output under PPAs to electric utilities (Sierra Pacific Power Company, Nevada Power Company, Peninsula Clean Energy, SCPPA and Idaho Power Company). All of the utilities except SCPPA are regulated by their respective state public utilities commissions. Sierra Pacific Power Company and Nevada Power Company, which merged and are doing business as NV Energy, are regulated by the PUCN. Peninsula Clean Energy, is regulated by the CPUC.

Under Hawaiian law, non-fossil generators are not subject to regulation as public utilities. Hawaiian law provides that a geothermal power producer is to negotiate the rate for its output with the public utility purchaser. If such rate cannot be determined by mutual accord, the PUCH will set a just and reasonable rate. If a non-fossil generator in Hawaii is a Qualifying Facility, federal law applies to such Qualifying Facility and the utility is required to purchase the energy and capacity at its avoided cost. The rates for our power plant in Hawaii are established under a long-term PPA with HELCO.

### Environmental Permits

U.S. environmental permitting regimes with respect to geothermal projects center upon several general areas of focus. The first involves land use approvals. These may take the form of Special Use Permits or Conditional Use Permits from local planning authorities or a series of development and utilization plan approvals and right of way approvals where the geothermal facility is entirely or partly on BLM or United States Forest Service lands. Certain federal approvals require a review of environmental impacts in conformance with the federal National Environmental Policy Act. In California, some local permit approvals require a similar review of environmental impacts under a state statute known as the California Environmental Quality Act. These federal and local land use approvals typically impose conditions and restrictions on the construction, scope and operation of geothermal projects.

The second category of permitting focuses on the installation and use of the geothermal wells themselves. Geothermal projects typically have three types of wells: (i) exploration wells designed to define and verify the geothermal resource, (ii) production wells to extract the hot geothermal liquids (also known as brine) for the power plant, and (iii) injection wells to inject the brine back into the subsurface resource. For example, on BLM lands in Nevada, California, Oregon, and Idaho, the well permits take the form of geothermal drilling permits for well installation. Approvals are also required to modify wells, including for use as production or injection wells. For all wells drilled in Nevada, a geothermal drilling permit must be obtained from the Nevada Division of Minerals. Those wells in Nevada to be used for injection will also require UIC permits from the Nevada Division of Environmental Protection and Bureau of Water Pollution Control. All geothermal wells drilled in Oregon (except on tribal lands) require a geothermal well drilling permit from the Oregon Department of Geology and Mineral Industries. All geothermal wells drilled in Idaho require a well construction permit from the IDWR and injection wells also require UIC permitting through IDWR. Geothermal wells on private lands in California require drilling permits from the California Department of Conservation’s DOGGR. The eventual designation of these installed wells as individual production or injection wells and the ultimate closure of any wells is also reviewed and approved by DOGGR pursuant to a DOGGR-approved Geothermal Injection Program.

A third category of permits involves the regulation of potential air emissions associated with the construction and operation of wells and power plants and surface water discharges associated with construction and operations activities. Generally, each well and plant requires a preconstruction air permit and storm water discharge permit before earthwork can commence. In addition, in some jurisdictions the wells that are to be used for production require, and those used for injection may require air emissions permits to operate. Internal combustion engines and other air pollutant emissions sources at the projects may also require air emissions permits, including to manage fugitive dust emissions during construction. For our projects, these permits are typically issued at the state or county level. Permits are also required to manage storm water during project construction and to manage drilling mud from well construction, as well as to manage certain discharges to surface impoundment, if any.

A fourth category of permits, required in Nevada, California, Oregon, and Idaho, includes ministerial permits such as building permits, hazardous materials storage and management permits, and pressure vessel operating permits. We are also required to obtain water rights permits in Nevada if water cooling is being used at the power plant. In addition to permits, there are various regulatory plans and programs that are required, including risk management plans (federal and state programs) and hazardous materials management plans (in California).

In some cases, our projects may also require permits, issued by the applicable federal agencies or authorized state agencies, regarding threatened or endangered species, permits to impact wetlands or other waters and notices of construction of structures which may have an impact on airspace. Environmental laws and regulations may change in the future that may modify the time to receive such permits and associated costs of compliance.

Our BESS projects are subject to similar permitting and regulatory compliance requirements. All of our current BESS projects are located on privately owned land and may require ministerial permits from local agencies as described above or undergo a state environmental permitting process (e.g., under the California Environmental Quality Act) with the city or county as the lead permitting agency. Storage projects are also required to comply with all applicable federal, state, and local laws and regulations, and similar to geothermal projects, may require various regulatory plans and programs including emergency action plans and fire response plans.

As of the date of this report, all of the material environmental permits and approvals currently required for our operating power plants and BESS projects have been obtained. We sometimes experience regulatory delays in obtaining various environmental permits and approvals required for projects in development and construction. These delays may lead to increases in the time and cost to complete these projects. Our operations are designed and conducted to comply with applicable environmental permit and approval requirements. Non-compliance with any such requirements could result in fines and penalties and could also affect our ability to operate the affected project.

### Environmental Laws and Regulations

Our facilities and operations are subject to a number of federal, state, local and foreign environmental laws and regulations relating to development, construction and operation. In the U.S, these may include the Clean Air Act, the Clean Water Act, the Emergency Planning and Community Right-to-Know Act, the Endangered Species Act, the National Environmental Policy Act, the Resource Conservation and Recovery Act, and related state laws and regulations.

Our geothermal operations involve significant quantities of brine (substantially, all of which we reinject into the subsurface) and scale, both of which can contain materials (such as arsenic, antimony, lead, and naturally occurring radioactive materials) in concentrations that exceed regulatory limits used to define hazardous waste. We also use various substances, including isopentane and industrial lubricants that could become potential contaminants and are generally flammable. As a result, our projects are subject to domestic and foreign federal, state and local statutory and regulatory requirements regarding the generation, handling, transportation, use, storage, treatment, fugitive emissions, and disposal of hazardous substances. The cost of investigation and removal or remediation activities associated with a spill or release of such materials could be significant. Hazardous materials are also used in our equipment manufacturing operations in Israel.

Although we are not aware of any mismanagement of these materials, including any mismanagement prior to the acquisition of some of our power plants that has materially impaired any of the power plant sites, any disposal or release of these materials onto the power plant sites, other than by means of permitted injection wells, could lead to contamination of the environment and result in material cleanup requirements or other responsive obligations under applicable environmental laws.

### Regulation Related to the Energy Storage Segment

Our participation in the energy storage space and in energy management requires us to obtain and maintain certain additional authorizations and approvals. These include (1) authorization from FERC to make wholesale sales of energy, capacity, and ancillary services at market-based rates, and (2) membership status with eligibility to serve designated contractual functions in the ISO/RTOs of PJM, NYISO, CAISO, ISO-NE, and ERCOT. Among other requirements, our market-based rate sellers are subject to certain market behavior and anti-market manipulation rules and, if any of our subsidiaries were deemed to have violated any one of those rules, such subsidiary could be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of market-based rate authority, as well as criminal and civil penalties. If the market-based rate authority for one (or more) of our subsidiaries was revoked or it was not able to obtain market-based rate authority when necessary, and it was required to sell energy on a cost-of-service basis, it could become subject to the full accounting, record keeping and reporting requirements of FERC. In the future, we may need to obtain and maintain similar membership and eligibility status with other ISO/RTOs in order to offer such services in their respective areas.

### Regulation of the Electric Utility Industry in our Foreign Countries of Operation

The following is a summary overview of certain aspects of the electric industry in the foreign countries in which we have an operating geothermal power plant. As such, it should not be considered a full statement of the laws in such countries or all of the issues pertaining thereto.

### Guatemala

The General Electricity Law of 1996, Decree 93-96, created a wholesale electricity market in Guatemala and established a new regulatory framework for the electricity sector. The law created a new regulatory commission, the CNEE, and a new wholesale power market administrator, the AMM, for the operation and administration of the sector. The AMM is a private not-for-profit entity. The CNEE functions as an independent agency under the Ministry of Energy and Mines and is in charge of regulating, supervising, and controlling compliance with the electricity law, overseeing the market and setting rates for transmission services, and distribution to medium and small customers. All distribution companies must supply electricity to such customers pursuant to long-term contracts with electricity generators. Large customers can contract directly with the distribution companies, electricity generators or power marketers, or buy energy in the spot market. Guatemala has approved a Law of Incentives for the Development of Renewable Energy Power plants, Decree 52-2003, in order to promote the development of renewable energy power plants in Guatemala. This law provides certain benefits to companies utilizing renewable energy, including a 10-year exemption from corporate income tax and VAT on imports and customs duties. On September 16, 2008, CNEE issued a resolution that approved the Technical Norms for the Connection, Operation, Control and Commercialization of the Renewable Distributed Generation and Self-producers Users with Exceeding Amounts of Energy. This Technical Norm was created to regulate all aspects of generation, connection, operation, control and commercialization of electric energy produced with renewable sources to promote and facilitate the installation of new generation plants, and to promote the connection of existing generation plants which have excess amounts of electric energy for commercialization. It is applicable to projects with a capacity of up to 5 MW. At present, the General Electricity Law and the Law of Incentives for the Development or Renewable Energy Power Plants are still in force.

### Kenya

The electric power sector in Kenya is regulated by the Kenyan Energy Act. Among other things, the Kenyan Energy Act provides for the licensing of electricity power producers and public electricity suppliers or distributors. KPLC is the major licensed public electricity supplier and has a virtual monopoly in the distribution of electricity in the country with the exception of a few off-grid, which have recently been licensed by the EPRA. The Kenyan Energy Act permits IPPs to install power generators and sell electricity to KPLC, which is owned by various private and government entities, and which currently purchases energy and capacity from other IPPs in addition to our Olkaria III complex. The electricity sector is regulated by the EPRA under the Kenyan Energy Act. KPLC’s retail electricity rates are subject to approval by the EPRA. The EPRA has an expanded mandate to regulate not just the electric power sector but the entire energy sector in Kenya. Transmission of electricity is now undertaken by KETRACO while another company, GDC, is responsible for geothermal assessment, drilling of wells and sale of steam for electricity operations to IPPs and KenGen. Both KETRACO and GDC are wholly owned by the government of Kenya. Renewable energy dominated by geothermal, wind and, presently at a lower level, solar is one of the key energy sub-sectors in Kenya contributing significantly to the overall energy mix as a result of the implementation of the feed-in- tariff policy by the Ministry of Energy. Under the national constitution enacted in August 2010, formulation of energy policy (including electricity) and energy regulation are functions of the national government. However, the constitution lists the planning and development of electricity and energy regulation as a function of the county governments (i.e. the regional or local level where an individual power plant is or is intended to be located).

### Indonesia

The Electricity Law of 2009 (in conjunction with Job Creation Act No. 11 of 2020/Omnibus Law) is the principal regulation for electricity industry in Indonesia which divides the industry into two broad categories: (1) electrical power provision, covering electric power generation, transmission, distribution and sales and (2) electrical power support such as services (consulting, construction, installation, operation & maintenance, certification & training, testing etc.) and manufacture (tools, power plant equipment, cables, electrical equipment, etc.). Electrical power provision business is dominated by PLN (a state-owned enterprise), which is the sole owner of transmission and distribution assets and 70% of the power generation assets. Private sector participation in power generation is allowed through an IPP scheme, mostly done through tenders or direct appointment for some power sources such as geothermal. Geothermal power is regulated by The Geothermal Law issued in 2014 (as also amended by the Indonesian Omnibus Law in 2020), that endorses private participation as geothermal IPP. Central government conduct tenders for geothermal fields, awarding Geothermal Business License for the winner. Geothermal Business License holder can conduct exploration and feasibility studies within five years and subject to two times one-year extensions, conduct well development and power plant construction and sell the electricity generated to PLN for a maximum of 30 years. Prior to the expiration of the Geothermal License, the IPP can propose to extend the license for an additional 20 years. In 2021, Presidential Regulation No. 112 was enacted with the aim of accelerating Renewable Energy. This regulation replaces the basis of the renewable energy tariff from the average electricity generation basic cost to ceiling price. In this scheme, the tariff is negotiated between IPP and PLN and must not be higher than the ceiling tariff set for particular type of renewable energy power plant, which then is multiplied by a factor based on location.

### Guadeloupe

EDF is the transmission and distribution utility in Guadeloupe and also operates a significant portion of Guadeloupe’s fossil fuel energy generation. There are also a number of IPPs in Guadeloupe, primarily producing renewable electricity. The electricity sector in Guadeloupe is regulated by the Commission Regulation of Energy (CRE), which also regulates EDF’s operations in mainland France and its other overseas territories. The electricity sector in Guadeloupe is characterized by both enabling features and obstacles with respect to renewable energy. One of the most influential enabling features is a French law requiring the utility to purchase power from any interconnected renewable generator. The major obstacle preventing further uptake of renewable electricity generation is the cap on variable generation at 30% of instantaneous system load. According to the multi-annual energy program (PPE) for Guadeloupe, the island aims to reach total energy independence by 2030. The program outlines the development schedule with an emphasis on solar, wind and geothermal growth for the years 2023-2026. The PPE also predict a geothermal installed capacity of 78MW by 2028.

### Honduras

In 2014, Honduras approved its new Law of Electrical Industry, which provides the legal framework for the electricity sector and replaces the previous Electricity Subsector Framework Law. The Law establishes technology-specific auctions for renewable energy. It creates the Regulatory Commission of Electric Power (CREE) as the entity in charge of supervising the bidding processes and the awarding of PPAs. The CREE is also responsible for granting study permits for the construction of generation projects that use renewable natural resources. Permits will have a maximum duration of two years, and will be revoked if no studies have been initiated within a period of six months and the reports required by the CREE have not been submitted. The new Law also establishes that all new capacity must be contracted through auctions and that the government can set a minimum quota for renewables in each auction. With respect to metering, after previous regulation applied legal incentives to renewable energy metering, the new law mandates utilities to buy excess power and credit it towards monthly bills and to install bi-directional meters.

Among others, the objectives of the law are to adapt the electricity sector’s legislation to the Framework Treaty for the Central American Electricity Market, which Honduras is a party to, and update the operating rules in the country’s electricity industry by incorporating structures and modern practices to increase the sector’s efficiency and competency in the production and marketing of electricity services.

With the passage of this new law, Honduras has moved into a new and open market. Under this legislation, all aspects of the market have been opened to private parties. This legislation is still being implemented within the market.

Honduras has also approved a Law of Incentives for Renewable Energy Projects, Decree 70-2007, further amended by Decree 138-2013, with additional incentives to solar PV projects, etc. The purpose, as in other countries of the region, is to promote the development of renewable energy power plants. Laws provide certain benefits to companies that generate power through renewable sources, including a 10-year exemption from corporate income tax and VAT on imports and customs duties, a fast track process for certain permits and a Sovereign Guaranty by the Central Government for the payments of the off-taker, the Public Utility Company, ENEE. At present, the Law of the Electrical Industry and the Laws of Incentives for Renewable Energy Projects are still in force.

## Risk factors

As filed, 118,518 characters.

The following risk factors should be read carefully in connection with evaluating us and this Annual Report. Certain statements in “Risk Factor” are forward-looking statements. See “Cautionary Note Regarding Forward-Looking Statements” elsewhere in this Annual Report.

**Risks Related to the Company’s Business and Operation**

***Our financial performance depends on the successful operation of our geothermal, REG and Solar PV power plants under the Electricity segment, as well as our Energy Storage facilities, which are subject to various operational risks.***

Our financial performance depends on the successful operation of our geothermal REG and Solar PV power plants. In connection with such operations, we derived 86.0% of our total revenues for the year ended December 31, 2022 from the sale of electricity. The cost of operation and maintenance and the operating performance of our geothermal power, REG and Solar PV power plants may be adversely affected by a variety of factors, including:

- regular and unexpected maintenance and replacement expenditures;
- shutdowns due to the breakdown or failure of our equipment or third party equipment of the transmission serving utility;
- labor disputes;
- labor market risk;
- the presence of hazardous materials on our power plant sites;
- continued availability of cooling water supply;
- catastrophic events such as fires, explosions, earthquakes, volcanic activity, landslides, floods, releases of hazardous materials, severe weather storms or other weather events (including weather conditions associated with climate change, or similar occurrences affecting our power plants or any of the power purchasers or other third parties providing services to our power plants, such as the 2018 volcanic eruption that occurred in Hawaii's Big Island that impacted our Puna project, as discussed elsewhere in this Annual Report;
- the aging of power plants (which may reduce their availability and increase the cost of their maintenance);
- unsuccessful augmentation of batteries or other necessary equipment; and
- cyber-attacks that may interrupt the operation of our power plants.

Any of these events could significantly increase the expenses incurred by our storage facilities or our power plants, or could reduce the overall effectiveness of our storage facilities or the generating capacity of our power plants and could significantly reduce or entirely eliminate the revenues generated by one or more of our power plants, which in turn would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flows.

***Our exploration, development, and operation of geothermal energy resources are subject to geological risks and uncertainties, which may result in decreased performance or increased costs for our power plants.***

Our primary business involves the exploration, development, and operation of geothermal energy resources. These activities are subject to uncertainties that, in certain respects, are similar to those typically associated with oil and gas exploration, development, and exploitation, such as dry holes, uncontrolled releases, and pressure and temperature decline. Any of these uncertainties may increase our capital expenditures and our operating costs or reduce the efficiency of our power plants. We may not find geothermal resources capable of supporting a commercially viable power plant at exploration sites where we have conducted tests, acquired land rights, and drilled test wells, which would adversely affect our development of geothermal power plants. Further, since the commencement of their operations, several of our power plants have experienced geothermal resource cooling, uncontrolled flow and/or reservoir pressure decline in the normal course of operations. Because geothermal reservoirs are complex geological structures, we can only estimate their geographic area and sustainable output. The viability of geothermal power plants depends on different factors directly related to the geothermal resource (such as the temperature, pressure, storage capacity, transmissivity, and recharge) as well as operational factors relating to the extraction or reinjection of geothermal fluids. Our geothermal energy power plants may also suffer an unexpected decline in the capacity of their respective geothermal wells and are exposed to a risk of geothermal reservoirs not being sufficient for sustained generation of the electrical power capacity desired over time. A recent example is the Olkaria complex, which experienced a reduction in generation due to lower performance of the wellfield. We are working to increase the capacity back. Also, in the Sarulla complex, we experienced a reduction in generation primarily due to wellfield issues at one of its power plants, as well as equipment failures which resulted in a decrease in profitability. During the second quarter of 2022, Sarulla agreed with its banks on a framework that will enable it to perform remediation work that is aimed to restore the plant’s performance, however, uncertainty remains regarding Sarulla’s ability to meet the plan and the Company is evaluating the impact of the plan on future performance. Another recent example, in the fourth quarter 2022 we recorded a non-cash impairment loss of $30.5 million related to our Brawley power plant in California that has been generating electricity that is lower than its generating capacity of 13MW due to continuous wellfield issues which resulted in higher than expected operating costs and lower than expected electricity revenues. We are following the remediation plans as well as assessing the accounting impact and its implication on our financial statements and our investment in the Sarulla complex.

Another aspect of geothermal operations is the management and stabilization of subsurface impacts caused by fluid injection pressures of production and injection fluids to mitigate ground subsidence or inflation. Inflation and subsidence, if not controlled, can adversely affect farming operations and other infrastructure at or near the land surface.

Additionally, active geothermal areas, such as the areas in which our power plants are located, may be subject to frequent low-level seismic disturbances. Serious seismic disturbances, volcanic eruptions and lava flows are possible and could result in damage to our power plants (or transmission lines used by customers who buy electricity from us) or equipment or degrade the quality of our geothermal resources to such an extent that we could not perform under the PPA for the affected power plant, which in turn could reduce our net income and materially and adversely affect our business, financial condition, future results and cash flow. If we suffer a serious seismic disturbance, volcanic eruptions and lava flows, our business interruption and property damage insurance may not be adequate to cover all losses sustained as a result thereof. In addition, insurance coverage may not continue to be available in the future in amounts adequate to insure against such seismic disturbances, volcanic eruptions and lava flows.

Furthermore, absent additional geologic/hydrologic studies, any increase in power generation from our geothermal power plants, failure to reinject the geothermal fluid or improper maintenance of the hydrological balance may affect the operational duration of the geothermal resource and cause it to decline in value over time and may adversely affect our ability to generate power from the relevant power plant.

***We may decide not to implement, or may not be successful in implementing, one or more elements of our multi-year strategic plan, and the plan as implemented may not achieve its goal of enhancing shareholder value through the long-term growth of our Company***

We are implementing a multi-year strategic plan to:

- strengthen our core geothermal business in the United States as well as globally;
- establishing a strong market position in the IFM energy storage market; and
- exploring opportunities in new areas by looking for synergistic growth opportunities utilizing our core competence, market reputation as a successful company and new market opportunities focused upon environmental solutions.

There are uncertainties and risks associated with our strategic plan, including with respect to implementation and outcome. We may decide to change, or to not implement, one or more elements of the plan over time or we may not be successful in implementing one or more elements of the plan, in each case for a number of reasons. For example, we may face significant challenges and risks expanding into the energy storage market (or expanding our core geothermal business), including:

- our ability to compete with the large number of other companies pursuing similar business opportunities in energy storage and solar PV power generation, many of which already have established businesses in these areas and/or have greater financial, strategic, technological or other resources than we have;
- our ability to obtain financing on terms we consider acceptable, or at all, which we may need, for example, to develop new projects, to obtain any technology, personnel, intellectual property, or to acquire one or more existing businesses as a platform for our expansion, or to fund internal research and development, for energy storage and solar PV electric power generation products and services;
- our ability to provide energy storage services that keep pace with rapidly changing technology, customer preferences, equipment costs, increasing raw materials and transportation costs, market conditions and other factors that are unknown to us now that will impact these markets;
- our ability to manage the risks and uncertainties associated with our operating storage facilities and future development of storage and geothermal projects which may operate as "merchant" facilities without long-term sales agreements, including the variability of revenues and profitability of such projects;
- our ability to devote the amount of management time and other resources required to implement this plan, while continuing to grow our core geothermal and recovered energy businesses; and
- our ability to recruit appropriate employees and labor market challenges.

Strengthening our core geothermal business to new customers and geographical areas will have many of the same risks and uncertainties as those outlined above.

Implementing the plan may also involve various costs, including, among other things:

- opportunity costs associated with foregone alternative uses of our resources;
- various expense items that will impact our current financial results; and
- asset revaluations (for example, businesses or other assets acquired for new energy storage or solar PV power generation products or services may suffer impairment charges, as a result of rapidly changing technology, market conditions or otherwise).

These costs may not be recovered, in whole or in part, if one or more elements of the plan are not successfully implemented. These costs, or the failure to implement successfully one or more elements of the plan, could adversely affect our reputation and the reputation of our subsidiaries and could materially and adversely affect our business, financial condition, future results and cash flow.

Apart from the risks associated with implementing the plan, the plan itself will expose us to other risks and uncertainties once implemented. Expanding our customer base may expose us to customers with different credit profiles than our current customers. Expanding our geographic base will subject us to risks associated with doing business in new foreign countries in which we will have to learn the business and political environment. In addition, expanding into new technologies will expose us to new risks and uncertainties that are unknown to us now in addition to the risks and uncertainties that may be similar to those we now face. The success of the plan, once implemented, will depend, among other things, on our ability to manage these risks effectively.

The trading price of our common stock could decline if securities, industry analysts or our investors disagree with our strategic plan or the way we implement it. Accordingly, there is no assurance that the plan will enhance shareholder value through long-term growth of the Company to the extent currently anticipated by our management or at all.

***Our investments in battery energy storage system (BESS) technology involves new technologies with relatively limited history with respect to reliability and performance and may not perform as expected. In addition, our investments may be negatively affected by a number of factors, including increases in storage costs, \[risk of fire\] and volatility in electricity pricing.***

We devote resources to research and development related to our energy storage segment, and the ability of these BESS facilities to meet our performance expectations is subject to the risks inherent in newly constructed facilities, including, but not limited to, system failures, outages and design and/or construction flaws, latent defects and degradation of equipment in excess of our expectations. Battery storage facilities utilize new technologies with a relatively limited history with respect to reliability and performance. We will need to innovate in order to keep pace with industry developments and customer expectations, and there is no guarantee that such new technologies will perform as expected. If any of our battery energy storage services contains manufacturing defects or any undetected defects, errors or bugs in hardware or software, our business and financial results could be adversely affected.

In addition, our investments in BESS facilities may be negatively affected by increases in storage costs, and the industry has recently experienced, and it is still facing, challenges in the development of new energy storage projects due to global supply chain constraints and inflation, which has caused an increase in prices and a shortage of core components of energy storage projects, specifically batteries. Our projects under development have experienced delays as a result of these challenges.

The revenues from our BESS facilities fluctuate over time since a large portion of such revenues are generated in the merchant markets, where price volatility is inherent\[; however, we may be required to guarantee an electricity customer’s cost savings and if such cost savings decrease below the guaranteed amount, due to a decrease in retail peak electricity pricing or otherwise, we would be required to pay an amount equal to the difference between the customer’s actual cost savings and the guaranteed amount. Developments in alternative technologies may materially and also adversely affect demand for battery energy storage.

Our BESS projects are also subject to current permitting and regulatory compliance requirements and an evolving regulatory landscape at both the federal and state level. Our projects under development have experienced delays and may in the future experience delays as a result of these requirements. In addition, we may be required by local governmental agencies to restrict our battery charging services, and in February 2021, as a result of the power crisis in Texas, we incurred $9.1 million in losses associated with our Rabbit Hill facility because ERCOT restricted us from providing battery charging services from February 16, 2021 to February 19, 2021.

Any of these events could significantly increase the expenses incurred by our BESS facilities or could significantly reduce or entirely eliminate the revenues generated by one or more of our BESS facilities plants, which in turn would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flows.

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

Our businesses often rely on a single customer to purchase all or a significant portion of a facility’s output. The financial performance of these facilities depends on the ability of each customer to perform its obligations under a long-term agreement between the parties. A facility’s financial results could be materially and adversely affected if any of our customers fail to fulfill its contractual obligations and we are unable to find other customers in the marketplace to purchase at the same level of profitability. We cannot assure that such performance failures by our customers will not occur, or that if they do occur, such failures will not adversely affect the cash flows or profitability of our businesses. Moreover, there can be no assurance that we will be able to enter into replacement agreements on favorable terms or at all.

While we have historically been able to collect on substantially all of our receivable balances, we have received late payments and have amounts overdue from certain of our significant customers. In the Electricity segment, we are exposed to the credit and financial condition of KPLC that buys the power generated from our Olkaria III complex in Kenya. In 2022, KPLC accounted for 14.4% of our total revenues. There has been a deterioration in the collection from KPLC that became slower than in the past, and as of December 31, 2022, the amount overdue from KPLC in Kenya was $27.0 million of which $15.2 million was paid in January and February of 2023. Any change in KPLC's financial condition may adversely affect us.

In Honduras, as of December 31, 2022, the total amount overdue from ENEE was $13.9 million of which $2.6 million was collected in February 2023. In addition, due to continuing restrictive measures related to the COVID-19 pandemic in Honduras, the Company may experience additional delays in collection. The Company believes it will be able to collect all past due amounts in Honduras.

We are also exposed to the credit and financial condition of SCPPA and its municipal utility members that account for 21.5% of our total revenues, as customers that buy the output from seven of our geothermal power plants. Because our contracts with SCPPA are long-term, we may be adversely affected if the credit quality of any of these customers were to decline or if their respective financial conditions were to deteriorate or if they are otherwise unable to perform their obligations under our long-term contracts.

In addition, we generate a significant portion of our revenue from our two largest projects, the McGinness Hills complex in East Nevada and the Olkaria III Complex in Kenya, which together accounted for approximately 27.6% of the total generating capacity of our Electricity segment in 2022. These two facilities accounted for 28.5% of our total revenues for the year ended December 31, 2022. Any disruption to the operation of these facilities would have a disproportionately adverse effect on our revenues and on our profitability.

***Our global operations expose us to risks related to the application of international laws and regulations, any of which may adversely affect our business, financial condition, future results and cash flows.***

Our global operations in countries including Kenya, Turkey, Guadeloupe, Guatemala, Honduras, Indonesia and others require us to comply with the laws and regulations of various governments and regulatory authorities outside the United States in addition to legal and regulatory requirements in the United States. Such foreign laws or regulations may not provide the same type of legal certainty, rights, or judicial processes with respect to our contractual relationships in such countries, as are afforded to our operations in the United States. A failure to receive adequate judicial or enforcement protection of our contractual rights abroad may adversely affect our ability to fulfill our contracts successfully and generate revenues therefrom. In particular, the legal and regulatory systems in the foreign jurisdictions where we operate can be characterized by one or more of the following:

- Selective or inconsistent enforcement of laws or regulations, sometimes in ways that have been perceived as being motivated by political or financial considerations;
- A perceived lack of judicial and prosecutorial independence from political, social and commercial forces;
- A high degree of discretion on the part of the judiciary and governmental authorities;
- Legal and bureaucratic obstacles and corruption;
- Rapidly evolving legal systems whose systems may not always coincide with market developments.

We face additional risks inherent in conducting business internationally, including compliance with laws and regulations of many jurisdictions that apply to our international operations. These laws and regulations may apply to us, our subsidiaries, individual directors, officers, employees and agents, and may restrict our operations, trade practices, investment or acquisition decisions or partnership opportunities. These requirements include, but are not limited to, data privacy requirements, labor relations laws, tax laws, competition regulations, import and trade restrictions, economic sanctions, and export requirements.

In particular, our international operations are subject to United States and foreign anti-corruption laws and regulations, such as the Foreign Corrupt Practices Act of 1977, as amended (the “FCPA”) and other local laws that prohibit corrupt payments to governmental officials or certain payments or remunerations to customers. The FCPA prohibits United States companies and their officers, directors, employees and agents acting on their behalf from corruptly offering, promising, authorizing or providing anything of value to foreign officials for the purposes of influencing official decisions or obtaining or retaining business or otherwise obtaining favorable treatment. The FCPA also requires companies to make and keep books, records and accounts that accurately and fairly reflect transactions and dispositions of assets and to maintain a system of adequate internal accounting controls. As part of our business, we deal with state-owned business enterprises, the employees and representatives of which may be considered foreign officials for purposes of the FCPA. As a result, business dealings between our employees and any such foreign official could expose us to the risk of violating anti-corruption laws even if such business practices may be customary or are not otherwise prohibited between us and a private third party. Violations of these legal requirements are punishable by criminal fines and imprisonment, civil penalties, disgorgement of profits, injunctions, debarment from government contracts as well as other remedial measures.

Given the high level of complexity of these laws, there is a risk that some provisions may be breached by us, for example through fraudulent or negligent behavior of individual employees (or third parties acting on our behalf), our failure to comply with certain formal documentation requirements, or otherwise. Violations of these laws and regulations could result in fines, criminal sanctions against us, our officers or our employees, requirements to obtain export licenses, cessation of business activities in sanctioned countries, implementation of compliance programs and prohibitions on the conduct of our business. Any such violation could include prohibitions on our ability to offer our products in one or more countries and could materially damage our reputation, our brand, our ability to attract and retain employees, our business, our financial condition and our results of operations.

Furthermore, existing laws or regulations may be amended or repealed, and new laws or regulations may be enacted or issued. In addition, the laws and regulations of some countries may limit our ability to hold a majority interest in some of the power plants that we may develop or acquire, thus limiting our ability to control the development, construction and operation of such power plants, or our ability to import our products into such countries.

***Political, economic and other conditions in the emerging economies where we operate, including Israel, may subject us to greater risk than in the developed U.S. economy, which may have a materially adverse effect on our business.***

We have substantial operations outside of the United States, both in our Electricity segment and our Product segment. In 2022, 34.1% of our total revenues were derived from international operations, and our Electricity segment international operations had higher gross profit than our U.S. operations. In 2022 a substantial portion of international revenues came from Kenya and, to a lesser extent, from Honduras, Guatemala, Guadeloupe and other countries. Thus, disturbances to and challenges facing our foreign operations, especially in Kenya, could have impacts on our business ranging from moderate to severe. Our foreign operations and our exposure to foreign customers that are in most cases, government owned utilities, subject us to significant political, economic and financial risks, which vary by country, and include:

- changes in government policies or personnel;
- changes in general economic conditions;
- restrictions on currency transfer or convertibility;
- the adoption or expansion of trade restrictions, the occurrence or escalation of a “trade war,” or other governmental action related to tariffs or trade agreements or policies among the governments of the United States and countries where we operate;
- reduced protection for intellectual property rights in some countries;
- changes in labor relations;
- political instability and civil unrest, and risk of war;
- terrorist acts or other similar events;
- changes in the local electricity and/or geothermal markets;
- difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations;
- breach or repudiation of important contractual undertakings by governmental entities; and
- expropriation and confiscation of assets and facilities, including without adequate compensation.

*Electricity Segment*. In 2022, the international operations of the Electricity segment accounted for 25% of our total revenues, but accounted for 43% of our gross profit, 72% of our net income and 36% of our EBITDA. A substantial portion of Electricity segment international revenues came from Kenya (which also contributed disproportionately to our gross profit and net income) and, to a lesser extent, from Guadeloupe, Guatemala and Honduras. In Kenya, any break-up or potential privatization of KPLC, the power purchaser for our power plants located in Kenya, may adversely affect our Olkaria III complex and our overall results of operations. Additionally, in Guatemala the electricity sector was partially privatized, and it is currently unclear whether further privatization will occur in the future. Such developments may affect our Amatitlan and Zunil power plants if, for example, they result in changes to the prevailing tariff regime or in the identity and creditworthiness of our power purchasers.

*Product Segment.* With respect to our Product segment, 90% of our Product segment revenues in 2022 came from international sales, primarily Turkey. Since we primarily engage in sales in those markets where there is a geothermal reservoir, any such change might adversely affect geothermal developers in those markets and, subsequently, the ability of such developers to purchase our products.

*Generally.* Outbreaks of civil and political unrest and acts of terrorism have also occurred in several countries in Africa, the Middle East and Latin America, where we have operations, such as Kenya and Honduras. Kenya experienced numerous terrorist attacks in 2014 and 2015, and has experienced an upsurge in attacks in more recent years, including in early 2019, from extremist groups. Continued or escalated civil and political unrest and acts of terrorism in the countries in which we operate could result in our curtailing operations. In the event that countries in which we operate experience civil or political unrest or acts of terrorism, especially in events where such unrest leads to an unseating of the established government, our operations in such countries could be materially impaired.

As a result of these risks, we purchase certain types of political risk insurance policies for selected countries where we operate and which are exposed to political turmoil, geopolitical issues or political uncertainty. While such policies are designed to offer assistance with respect to some political incidents that could give rise to financial liability, it does not mitigate all of the above-mentioned risks. In addition, insurance proceeds received pursuant to our political risk insurance policies, where applicable, may not be adequate to cover all losses sustained as a result of any covered risks and may at times be pledged in favor of the power plant lenders as collateral. Also, insurance may not be available in the future with the scope of coverage and in amounts of coverage adequate to insure against such risks and disturbances. Any or all of the changes discussed above could materially and adversely affect our business, financial condition, future results and cash flow.

***Conditions in and around Israel, where the majority of our senior management and our main production and manufacturing facilities are located, may adversely affect our operations and may limit our ability to produce and sell our products or manage our power plants.***

The majority of our senior management and our main production and manufacturing facilities are located in Israel approximately 26 miles from the border with the Gaza Strip. As such, political, economic and security conditions in Israel and the Middle East region directly affect our operations.

The political instability and civil unrest in the Middle East and North Africa as well as the increased tension between Iran and Israel have raised new concerns regarding security in the region and the potential for armed conflict or other hostilities involving Israel, any of which could impede our ability to manufacture and support our products offerings. We could be adversely affected by any such hostilities, the interruption or curtailment of trade between Israel and its trading partners, or a significant downturn in the economic or financial condition of Israel. In addition, the sale of products manufactured in Israel may be adversely affected in certain countries by restrictive laws, policies or practices directed toward Israel or companies having operations in Israel. If our facilities become temporarily or permanently disabled by an act of terrorism or war, we may be required to develop alternative infrastructure and we may not be able to avoid service interruptions.

These events and conditions could disrupt our operations in Israel, which could materially and adversely affect our business, financial condition, future results, and cash flow.

In addition, political unrest and recent widespread protests in Israel against a planned judicial overhaul may cause investor concerns associated with such political unrest in Israel and potential changes in the judicial system. We cannot be certain whether the planned judicial overhaul will occur or in what form. As such, we cannot be certain on how investors will assess these matters and whether this assessment will adversely impact perception s of our business and our share price, or impact our business operations in Israel.

***Continued reduction in our Products backlog may affect our ability to fully utilize our main production and manufacturing facilities and may have a materially adverse effect on our business.***

In our Product segment, reduction in our backlog may affect our ability to fully utilize our manufacturing facility and we may incur higher costs that our Product segment revenues may not be able to cover or increase capital costs to develop our own power plants, which could materially and adversely affect our business, financial condition, future results, and cash flow.

***Some of our leases will terminate if we do not extract geothermal resources in “commercial quantities”, if we fail to comply with the terms or stipulations of such leases or any of the provisions of the Geothermal Steam Act or if the lessor under any such lease defaults on any debt secured by the relevant property, thus requiring us to enter into new leases or secure rights to alternate geothermal resources, none of which may be available on terms as favorable to us as any such terminated lease, if at all.***

Most of our geothermal resource leases are for a fixed primary term, and then continue for so long as geothermal resources are extracted in “commercial quantities” or pursuant to other terms of extension. The land covered by some of our leases (approximately 200,000 acres in the U.S. and approximately 15,000 acres elsewhere) is undeveloped and has not yet produced geothermal resources in commercial quantities. Leases that cover land which remains undeveloped and does not produce, or does not continue to produce, geothermal resources in commercial quantities and leases that we allow to expire, may terminate. In the event that a lease is terminated and we determine that we will need that lease once the applicable power plant is operating, we would need to enter into one or more new leases with the owner(s) of the premises that are the subject of the terminated lease(s) in order to develop geothermal resources from, or inject geothermal resources into, such premises or secure rights to alternate geothermal resources or lands suitable for injection. We may not be able to do this or may not be able to do so without incurring increased costs, which could materially and adversely affect our business, financial condition, future results and cash flow.

Additionally, pursuant to the terms of our BLM leases, we are required to conduct our operations on BLM-leased land in a workmanlike manner and in accordance with all applicable laws and BLM directives and to take all mitigating actions required by the BLM to protect the surface of and the environment surrounding the relevant land. Certain BLM leases contain additional requirements, some of which relate to the mitigation or avoidance of disturbance of any antiquities, cultural values or threatened or endangered plant, wildlife and species. In the event of a default under any BLM lease, or the failure to comply with such requirements, or any non-compliance with any of the provisions of the Geothermal Steam Act or regulations issued thereunder, the BLM may, 30 days after notice of default is provided to our relevant project subsidiary, suspend our operations until the requested action is taken or terminate the lease, either of which could materially and adversely affect our business, financial condition, future results and cash flow.

The fee interest in the land which is the subject of some of our leases (or subleases) may currently be or may become subject to encumbrances securing loans from third-party lenders to the lessor (or sublessor). Our rights as lessee (or sublessee) under such leases (or subleases) are or may be subject and subordinate to the rights of any such lender. Accordingly, a default by the lessor (or sublessor) under any such loan could result in a foreclosure on the underlying fee interest in the property and thereby terminate our leasehold interest and result in the shutdown of the power plant located on the relevant property and/or terminate our right of access to the underlying geothermal resources required for our operations.

***Reduced levels of recovered energy required for the operation of our REG power plants may result in decreased performance of such power plants.***

Our REG power plants generate electricity from recovered energy or so-called “waste heat” that is generated as a residual by-product of gas turbine-driven compressor stations and a variety of industrial processes. Any interruption in the supply of the recovered energy source, such as a result of reduced gas flows in the pipelines or reduced level of operation at the compressor stations, or in the output levels of the various industrial processes, may cause an unexpected decline in the capacity and performance of our recovered energy power plants.

***Our business development activities may not be successful and our projects under construction or facilities undergoing enhancement and repowering may encounter delays, which may impact our future growth.***

We are in the process of developing and constructing a number of new power plants. Our success in developing a project is contingent upon, among other things, negotiation of satisfactory engineering and construction agreements and obtaining PPAs and transmission services agreements, receipt of required governmental permits (including environmental permits), obtaining adequate financing, and the timely implementation and satisfactory completion of field development, testing and power plant construction and commissioning. We may be unsuccessful in accomplishing any of these matters or doing so on a timely basis such in cases where we have to handle legal proceedings with respect to environmental permits. Although we may attempt to minimize the financial risks attributable to the development of a project by securing a favorable PPA and applicable transmission services agreements, obtaining all required governmental permits and approvals and arranging, in certain cases, adequate financing prior to the commencement of construction, the development of a power project may require us to incur significant expenses for preliminary engineering, permitting and legal and other expenses before we can determine whether a project is feasible, economically attractive or capable of being financed.

Currently, we have geothermal projects and prospects under exploration, development or construction in the United States, as well as in Indonesia, Ethiopia, Guadeloupe, Guatemala, Madagascar and New Zealand and we intend to pursue the development of other new plants. In addition, our current growth plans include enhancement and repowering of a number of our operating facilities, including the Heber, Dixie Valley, Zunil, Beowawe and Puna power plants and involve replacement of old equipment and optimization of the geothermal field, including repair and enhancement of existing wells and drilling of new wells. Our completion of these facilities’ development and/or enhancement is subject to substantial risks, including:

- inability to secure a PPA;
- inability to secure transmission services agreements;
- inability to secure the required financing;
- cost increases and delays due to unanticipated shortages of adequate resources to execute the project such as equipment, material and labor;
- work stoppages resulting from force majeure events including riots, strikes and weather conditions;
- inability to obtain permits, licenses and other regulatory approvals;
- inability to satisfactorily complete field development and testing;
- failure to secure sufficient land positions for the wellfield, power plant and rights of way;
- failure by key contractors and vendors to timely and properly perform, including where we use equipment manufactured by others;
- inability to secure or delays in securing the required transmission line and/or capacity;
- adverse environmental and geological conditions (including, but not limited to, discoveries of contamination, protected plant or animal species or habitat, archaeological or cultural resources, or inclement weather conditions);
- adverse local business law;
- our attention to other projects and activities, including those in the solar energy and energy storage sectors; and
- changes in laws that mandate, incentivize or otherwise favor renewable energy sources.

Any one of these could give rise to delays, cost overruns, the termination of the plant expansion, construction or development or the loss (total or partial) of our interest in the project under development, construction, or expansion.

In addition, we enter into various types of arrangements with communities and joint venture partners, including in some cases, Indigenous peoples, for the development of projects. In some circumstances, we may be required to notify, consult, or obtain the consent of certain stakeholders, such as Indigenous peoples, landowners, and/or municipalities. In some jurisdictions where we have greenfield power projects, it may be possible to claim Indigenous rights to land and the existence or declaration of Indigenous title may affect the existing or future activities of our projects and impact our business, financial condition and results of operations. Certain of these communities and partners may have or may develop interests or objectives which are different from or even in conflict with our objectives. Any such differences could have a negative impact on the success of our projects.

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

We depend on transmission facilities owned and operated by others to deliver the power we sell from our power plants to our customers. If transmission is disrupted, or if the transmission capacity infrastructure is inadequate, of if there is a failure that requires long shutdown for repair, or if curtailment is required due to load system inefficiency, our ability to sell and deliver power to our customers may be adversely impacted and we may either incur additional costs or forego revenues. In addition, lack of access to new transmission capacity may affect our ability to develop new projects. Existing congestion of transmission capacity, as well as expansion of transmission systems and competition from other developers seeking access to expanded systems, could also affect our performance.

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

We have partners in several of our plants and we may continue in the future to develop and/or acquire and/or hold properties in joint ventures with other entities when circumstances warrant the use of these structures. These arrangements are often driven by the magnitude of capital required to complete acquisitions of generating assets, strategic partnering arrangements to access operating expertise, and other geothermal and energy industry wide trends that we presume will continue in the future. Where we hold a minority interest in a joint venture or share control or management with another party in a joint venture (such as in the case of our plant in Guadeloupe), our ability to influence joint venture operations may be limited. As such, our ownership of assets in joint ventures is subject to risks that may not be present with other methods of ownership, including:

- we could experience an impasse on certain decisions because we do not have sole decision-making authority, which could require us to expend additional resources on resolving such impasses or potential disputes, including arbitration or litigation;
- our joint venture partners could have investment goals that are not consistent with our investment objectives, including the timing, terms and strategies for any investments in the projects that are owned by the joint ventures, which could affect decisions about future capital expenditures, major operational expenditures and retirement of assets, among other things;
- our ability to transfer our interest in a joint venture to a third party may be restricted and the market for our interest may be limited;
- our joint venture partners may be structured differently than us for tax purposes, and this could impact our ability to fully take advantage of federal tax incentives available for renewable energy projects;
- our joint venture partners might become bankrupt, fail to fund their share of required capital contributions or fail to fulfill their obligations as a joint venture partner, which may require us to infuse our own capital into the venture on behalf of the partner despite other competing uses for such capital; and
- our joint venture partners may have competing interests in our markets and investments in companies that compete directly or indirectly with us that could create conflict of interest issues.

For example, we hold a 12.75% minority interest in the Sarulla complex and, as a result, cannot control the development of its remediation plan, pace of exploration or development or major drilling decisions. Because we may, in some instances, have a reduced level of influence over our joint ventures, we may not be able to realize some or all of the benefits that we believe will be created from our involvement. If any of the foregoing were to occur, our business, financial condition and results of operations could suffer as a result.

### Our operations could be adversely impacted by climate change.

We are susceptible to losses and interruptions caused by extreme weather conditions such as droughts, hurricanes, tsunamis, floods, wildfires, and water or other natural resource shortages, occurrences of which may increase in frequency and severity as a result of climate change. Climate change may also produce general changes in weather or other environmental conditions, including temperature or precipitation levels, and thus may impact consumer demand for electricity. Daily and seasonal fluctuations in temperature generally have a more significant impact on the generating capacity of geothermal energy plants than conventional power plants. Some of our power plants experience reduced generation in warm periods due to the lower heat differential between geothermal fluid and the ambient surroundings. While we generally account for the projected impact seasonal fluctuations in temperature based on our historic experience, the impact of climate change on traditional weather patterns has become more pronounced. This has reduced the certainty of our modelling efforts. For example, in 2019, we experienced prolonged elevated temperatures in the Western United States which impacted generating capacity at our facilities and adversely impacted our revenues in the fourth quarter of the year. To the extent weather conditions continue to be impacted by climate change, the generating capacity of certain of our facilities may be adversely impacted in a manner that we could not predict which may in turn adversely impact our results of operations. In addition, the potential physical effects of climate change, such as increased frequency and severity of storms, floods, and other climatic events, could disrupt our operations and cause us to incur significant costs to prepare for or respond to these effects.

Climate change could also affect the availability of a secure and economical supply of water, which is essential for the continued operation of some of our power plants that use water cooling systems. Ormat monitors water risk carefully. If it is determined that a water supply risk exists that could impact projected generation levels at any plant, risk mitigation efforts are identified and evaluated for implementation.

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

As a renewable energy solution provider, we are motivated to identify our opportunities and risks with respect to climate change and take efforts to reduce our GHG emissions and improve our energy efficiency. While we generally view this as an opportunity, uncertainty regarding nascent regulation in this area could also adversely affect us. In the United States, where we have a significant portion of our operations, no comprehensive climate change legislation has been implemented federally. The U.S. Environmental Protection Agency (the “EPA”) has adopted rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and reporting of GHG emissions from certain sources and implement standards directing the reduction of methane from certain facilities in the oil and gas sector. Additionally, various states have adopted or are considering adopting legislation and regulation focused on GHG cap-and-trade programs, carbon taxes, reporting and tracking programs and emissions limits. Uncertainty associated with these regulations, our inability to meet the demands of these regulations or our failure to predict accurately the impact of our response to these regulations could adversely affect our business and prospects.

In addition, the SEC proposed rules in March 2022 that would require public companies to include extensive climate-related disclosures in their SEC filings. Among other things, the proposed SEC rules, if adopted as written, would mandate disclosures on (i) GHG emissions, including Scope 3 emissions if material or part of a company's emissions goal, (ii) financial impact and expenditure metrics relating to severe weather and climate change and (iii) a company's use of scenario analysis and climate targets. Although the SEC has not finalized these rules, we would expect to incur substantial additional compliance costs to the extent these or similar rules are adopted. Such compliance costs could in turn adversely effect on our business or results of operations.

In addition to legal and regulatory requirements, growing stakeholder engagement with respect to sustainability matters could cause us to alter our business operations, which could require them to incur substantial expense. Any failure to comply with stakeholder requests, in particular, the ability to meet customer requirements or sustainability targets, could adversely impact the demand of our services and subject us to significant costs and liabilities and reputational risks, any of which could adversely affect our business, financial condition and results of operations.

***Geothermal projects that we plan to develop in the future, may operate as "merchant" facilities without long-term PPAs and therefore such projects will be exposed to market fluctuations.***

Geothermal projects that we plan to develop in the United States as part of our growth plans may operate as "merchant" facilities and sell electricity without long-term PPAs for some or all of their generating capacity and output. Merchant projects require that we sell directly into the market on a short term basis and our success with respect to any such projects depends, in large part, upon prevailing market prices. Given the volatility of commodity power prices, to the extent we are unable to secure the benefit of a long-term PPAs for these assets, we cannot be sure that we will be able to sell any or all of the power generated by these facilities at commercially attractive rates or that these facilities will be able to operate profitably. This could lead to future impairments of our property, plant and equipment resulting in economic losses and liabilities, which could have a material adverse effect on our results of operations, financial condition or cash flows.

***We may not be able to successfully conclude the transactions, integrate companies, which we acquired and may acquire in the future, which could materially and adversely affect our business, financial condition, future results and cash flow.***

Our strategy is to continue to expand in the future, including through acquisitions to enhance our geothermal portfolio and accelerate growth in our Electricity segment. Integrating acquisitions is often costly, and we may not be able to successfully integrate our acquired companies with our existing operations without substantial costs, delays or other adverse operational or financial consequences. Completion of M&A transactions may be subject to fulfilling conditions and receiving regulatory approval. Integrating our acquired companies involves a number of risks that could materially and adversely affect our business, including:

- failure of the acquired companies to achieve the results we expect;
- inability to retain key personnel of the acquired companies;
- risks associated with unanticipated events or liabilities; and
- the difficulty of establishing and maintaining uniform standards, controls, procedures and policies, including accounting controls and procedures.

If any of our acquired companies suffers customer dissatisfaction or performance problems, this could adversely affect the reputation of our group of companies and could materially and adversely affect our business, financial condition, future results and cash flow.

### We encounter intense competition in the energy storage market.

We are experiencing intense competition in the energy storage market from independent power producers, developers, and third-party investors. If we are unable, as a result of increased competition, to grow our energy storage portfolio while meeting our profitability goals, our business, financial condition, future results and cash flow could be materially and adversely affected.

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

A basic premise of our business model is that generating baseload power at geothermal power plants produces electricity at a competitive price. However, traditional coal-fired systems and gas-fired systems may under certain economic conditions produce electricity at lower average prices than our geothermal plants. In addition, there are other technologies that can produce electricity such as hydroelectric systems, fuel cells, microturbines, wind turbines, energy storage systems and solar PV systems. Some of these alternative technologies currently produce electricity at higher average prices than our geothermal plants while others produce electricity at lower average prices. It is possible that technological advances and economies of scale will further reduce the cost of alternate methods of power generation. It is also possible that energy technologies will compete with our basic premise of a firm (non-intermittent) renewable baseload power source by combining renewable technologies with energy storage to provide an alternative to firm baseload energy. If this were to happen, the competitive advantage of our power plants may be significantly impaired and will cause reduction and/or inability to sign new PPAs for our Electricity segment and new supply and EPC contracts for our Products segment.

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

Our existing intellectual property rights may not be adequate to protect our business. We occasionally file patent applications which cover our products (mainly power units based on the ORC) and systems (mainly geothermal power plants and industrial waste heat recovery plants for electricity production). However, the patent application process is expensive, time-consuming and complex and we may not be able to prepare, file, prosecute, maintain and enforce all necessary or desirable patent applications at a reasonable cost or in a timely manner. Patents may be invalidated and patents may not be issued on the basis of our patent applications. Additionally, the scope of patent protection can be reinterpreted after issuance. Even if our patent applications do issue as patents, they may not issue in a form that is sufficiently broad to protect our technology, prevent competitors or other third parties from competing with us or otherwise provide us with any competitive advantage. In addition, any patents issued to us or for which we have use rights may be challenged, narrowed, invalidated or circumvented. Third parties may initiate opposition, interference, re-examination, post-grant review, inter partes review, nullification or derivation actions, or similar proceedings challenging the inventorship, validity, enforceability or scope of our patents. An adverse determination in any such proceeding or litigation could reduce the scope of, or invalidate our patent rights, allow third parties to commercialize our technology and compete directly with us, without payment to us, or result in our inability to commercialize our technology without infringing third-party patent rights. Such proceedings also may result in substantial cost and require significant time from our management, even if the eventual outcome is favorable to us. Our competitors or other third parties may also be able to circumvent our patents by developing similar or alternative technologies in a non-infringing manner. Consequently, we do not know whether any of our technology will be protectable or remain protected by valid and enforceable patents.

In order to safeguard our unpatented proprietary know-how, trade secrets and technology, we rely on a combination of trade secret protection and non-disclosure provisions in agreements with employees and third parties having access to confidential or proprietary information. These measures may not adequately protect us from disclosure, use, reverse engineering, infringement, misappropriation or other violation of our proprietary information and other intellectual property rights by third parties. Furthermore, non-disclosure provisions can be difficult to enforce and, even if successfully enforced, may not be entirely effective. In addition, we cannot guarantee that we have entered into non-disclosure agreements with all employees and third parties that have or may have had access to our trade secrets and other confidential or proprietary information.

Even if we adequately protect our intellectual property rights, litigation may be necessary to enforce these rights, which could result in substantial costs to us and a substantial diversion of management attention. Furthermore, attempts to enforce our intellectual property rights against third parties could also provoke these third parties to assert their own intellectual property or other rights against us, or result in a holding that invalidates or narrows the scope of our rights, in whole or in part. Our success and ability to compete also depends in part on our ability to operate without infringing, misappropriating or otherwise violating the intellectual or proprietary rights of third parties. While we have attempted to ensure that our technology and the operation of our business does not infringe other parties' patents and other intellectual property or proprietary rights, our competitors or other third parties may assert that certain aspects of our business or technology infringe upon, misappropriate or otherwise violate their intellectual property or proprietary rights. In addition, former employers of our current, former or future employees may assert claims that such employees have improperly disclosed to us the confidential or proprietary information of these former employers. Infringement, misappropriation or other intellectual property violation claims, regardless of merit or ultimate outcome, can be expensive, hard to predict and time-consuming and can divert management’s attention from our core business. An assertion of an intellectual property infringement, misappropriation or other violation claim against us may result in adverse judgments, settlements on unfavorable terms or cause us to pay significant money damages, lose significant revenues, be prohibited from using the relevant technology or other intellectual property, or incur significant license, royalty or technology development expenses. Future litigation may also involve non-practicing entities or other intellectual property owners who have no relevant product offerings or revenue and against whom our own intellectual property may therefore provide little or no deterrence or protection.

### We may experience difficulties implementing and maintaining our new enterprise resource planning system

We purchased and in early 2023 implemented a new enterprise resource planning (“ERP”) system. ERP implementations are complex and time-consuming. The ERP system is critical to our ability to provide important information to our management, obtain and deliver products, provide services and customer support, send invoices and track payments, fulfill contractual obligations, accurately maintain books and records, provide accurate, timely and reliable reports on our financial and operating results or otherwise file our financial statements with the SEC and operate our business. ERP implementations also require transformation of business and financial processes in order to reap the benefits of the ERP system; any such transformation involves risks inherent in the conversion to a new computer system, including loss of information and potential disruption to our normal operations. In addition, any disruptions, delays or deficiencies in the ongoing maintenance of the new ERP system could adversely affect our ability to process orders, ship products, provide services and customer support, send invoices and track payments, fulfill contractual obligations, accurately maintain books and records, provide accurate, timely and reliable reports on our financial and operating results, or otherwise file our financial statements with the SEC and operate our business. Additionally, if the new system does not operate as intended, the effectiveness of our internal control over financial reporting could be adversely affected or our ability to assess it adequately could be delayed.

***A cyber-incident, cyber security breach, severe natural event or physical attack on our operational networks and information technology systems could have a material adverse effect on our financial condition, results of operations, liquidity and cash flows.***

We rely on information technology systems that allow us to create, store, retain, transmit and otherwise process proprietary and sensitive or confidential information, including our business and financial information, and personal information regarding our employees and third-parties. We also rely on our operational technology systems to manufacture equipment for our energy projects, operate our power plants and provide our services. In addition, we often rely on third-party vendors to host, maintain, modify and update our systems.

Our and our third-party vendors’ technology systems can be damaged by malicious events such as cyber and physical attacks, computer viruses, malicious and destructive code, phishing attacks, denial of service or information, as well as security breaches, natural disasters, fire, power loss, telecommunications failures, employee misconduct, human error, and third parties such as traditional computer hackers, persons involved with organized crime or foreign state or foreign state-supported actors. Furthermore, our disaster recovery planning may not be sufficient for all situations. Any failure, disruptions to or decrease in the functionality of our or our third-party vendors’ operational and information technology networks could impact our ability to maintain effective internal controls over financial reporting, cause harm to the environment, the public or our employees, and significantly disrupt and damage our assets and operations or those of third parties.

We and our third-party vendors have been, and may in the future be, subject to breaches and attempts to gain unauthorized access to our information technology systems or sensitive or confidential data, or to disrupt our operations. To date, none of these breaches or attempts has, individually or in the aggregate, resulted in a security incident with a material effect on our operations or our financial condition, results of operations, liquidity, or cash flows. Despite implementation of security and control measures, we and our third-party vendors have not always been able to, and there can be no assurance that we or our third-party vendors will be able to in the future, anticipate or prevent unauthorized access to our or our third-party vendors’ operational technology networks, information technology systems or data, or the disruption of our or our third-party vendors’ operations. The techniques used to obtain unauthorized access to our and our third-party vendors’ operational technology networks, information technology systems or data are constantly evolving and have become increasingly complex and sophisticated. Furthermore, such techniques change frequently and are often not detected until after they have been launched against a target. Therefore, we may be unable to anticipate these techniques and may not become aware in a timely manner of such a security breach, which could exacerbate any damage we experience. Such events could cause interruptions in the operation of our business, damage our operational technology networks and information technology systems, subject us to significant expenses, remediation costs, litigation, disputes, claims by third parties and regulatory actions or investigations that could result in damages, material fines and penalties, and harm to our reputation, any of which could have a material adverse effect on our financial condition, results of operations, liquidity, and cash flows. We may maintain cyber liability insurance that covers certain damages caused by cyber incidents. However, there is no guarantee that adequate insurance will continue to be available at rates that we believe are reasonable or that the costs of responding to and recovering from a cyber incident will be covered by insurance or recoverable in rates.

In addition, we are subject to various legislation, regulations, directives and guidelines from federal, state, local and foreign agencies, such as FERC, that are intended to strengthen cybersecurity measures required for information and operational technology and critical energy infrastructure and that apply to the collection, use, retention, protection, disclosure, transfer and other processing of personal information. In California, for example, the California Consumer Privacy Act (the “CCPA”) imposes obligations on businesses to be transparent with their data privacy practices and vests consumers with rights to access and delete the personal information held by businesses. These requirements will become even more robust under the California Privacy Rights Act (the “CPRA”) which amends the CCPA to, among other things, extend consumer rights and business obligations to employees, and will become effective on January 1, 2023. These cybersecurity, data protection and privacy law regimes continue to evolve and may result in ever-increasing public scrutiny and escalating levels of capital expenditures, regulatory enforcement, sanctions and fines and increased costs for compliance. We have instituted security measures and safeguards to protect our operational systems and information technology assets, including certain safeguards required by FERC. Despite our implementation of security measures and safeguards, any failure to comply with FERC or any of these legal requirements could result in enforcement action against us, including fines, imprisonment of company officials and public censure, any of which could harm our reputation and have a material adverse effect on our financial condition, results of operations, liquidity, and cash flows.

### Risks Related to Governmental Regulations, Laws and Taxation

***Our financial performance could be adversely affected by changes in the legal and regulatory environment affecting our operations.***

All of our power plants are subject to extensive regulation, and therefore changes in applicable laws or regulations, or interpretations of those laws and regulations, could result in increased compliance costs, the need for additional capital expenditures or the reduction of certain benefits currently available to our power plants. The structure of domestic and foreign energy regulation currently is, and may continue to be, subject to challenges, modifications, the imposition of additional regulatory requirements, and restructuring proposals. We or our power purchasers may not be able to obtain all regulatory approvals that may be required in the future, or any necessary modifications to existing regulatory approvals, or maintain all required regulatory approvals. In addition, the cost of operation and maintenance and the operating performance of geothermal power plants may be adversely affected by changes in certain laws and regulations, including tax laws.

Any changes to applicable laws and regulations or interpretations of those laws and regulations could significantly increase the regulatory-related compliance, tax and other expenses incurred by the power plants and could significantly reduce or entirely eliminate the revenues generated by one or more of the power plants, which in turn would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flow.

***Pursuant to the terms of some of our PPAs with investor-owned electric utilities and publicly-owned electric utilities in states that have renewable portfolio standards, the failure to supply the contracted capacity and energy thereunder may result in the imposition of penalties.***

Pursuant to the terms of certain of our PPAs, we may be required to make payments to the relevant power purchaser under certain conditions, such as shortfall in delivery of renewable energy and energy credits, and not meeting certain performance threshold requirements, as defined in the relevant PPA. The amount of payment required is dependent upon the level of shortfall in delivery or performance requirements and is recorded in the period the shortfall occurs. In addition, if we do not meet certain minimum performance requirements, the capacity of the relevant power plant may be permanently reduced. Any or all of these considerations could materially and adversely affect our business, financial condition, future results and cash flow.

***If any of our domestic power plants loses its current Qualifying Facility status under PURPA, or if amendments to PURPA are enacted that substantially reduce the benefits currently afforded to Qualifying Facilities, our domestic operations could be adversely affected.***

Most of our domestic power plants are Qualifying Facilities pursuant to PURPA, which largely exempts the power plants from the FPA, and certain state and local laws and regulations regarding rates and financial and organizational requirements for electric utilities.

If any of our domestic power plants were to lose its Qualifying Facility status, such power plant could become subject to the full scope of the FPA and applicable state regulation. The application of the FPA and other applicable state regulation to our domestic power plants could require our operations to comply with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility.

If a domestic power plant were to lose its Qualifying Facility status, it would become subject to full regulation as a public utility under the FPA, and the rates charged by such power plant pursuant to its PPAs may be subject to the review and approval of FERC. FERC, upon such review, may determine that the rates currently set forth in such PPAs are not appropriate and may set rates that are lower than the rates currently charged. In addition, FERC may require that the affected domestic power plant refund amounts previously paid by the relevant power purchaser to such power plant. Even if a power plant does not lose its Qualifying Facility status, pursuant to regulations issued by FERC for Qualifying Facility power plants above 20 MW, if a power plant’s PPA is terminated or otherwise expires, and the subsequent sales are not made pursuant to a state’s implementation of PURPA, that power plant will become subject to FERC’s ratemaking jurisdiction under the FPA. Moreover, a loss of Qualifying Facility status also could permit the power purchaser, pursuant to the terms of the particular PPA, to cease taking and paying for electricity from the relevant power plant or, consistent with FERC precedent, to seek refunds of past amounts paid. This could cause the loss of some or all of our revenues payable pursuant to the related PPAs, result in significant liability for refunds of past amounts paid, or otherwise impair the value of our power plants. If a power purchaser were to cease taking and paying for electricity or seek to obtain refunds of past amounts paid, there can be no assurance that the costs incurred in connection with the power plant could be recovered through sales to other purchasers or that we would have sufficient funds to make such payments. In addition, the loss of Qualifying Facility status would be an event of default under the financing arrangements currently in place for some of our power plants, which would enable the lenders to exercise their remedies and enforce the liens on the relevant power plant.

Pursuant to the Energy Policy Act of 2005, FERC also has the authority to prospectively lift the mandatory obligation of a utility under PURPA to offer to purchase the electricity from a Qualifying Facility if the utility operates in a workably competitive market. Our existing PPAs between a Qualifying Facility and a utility are not affected. If, in addition to the California utilities’ waiver of the mandatory purchase obligation for QF projects that exceed 20 MW described in the risk factor above, the utilities in the other regions in which our domestic power plants operate were to be relieved of the mandatory purchase obligation, they would not be required to purchase energy from the power plant in the region under Federal law upon termination of the existing PPA or with respect to new power plants, which could materially and adversely affect our business, financial condition, future results and cash flow. Moreover, FERC has the authority to modify its regulations relating to the utility’s mandatory purchase obligation under PURPA, which could result in the reduction in the purchase obligation of California and other utilities to a level below 5 MW, or the elimination of the purchase obligation. If that were to occur it could materially and adversely affect our business, financial condition, future results and cash flow.

The PURPA and QF described risks identified above are not likely to affect our Nevada based facilities that entered into PPAs with NV Energy as the off-taker after Nevada initially adopted its RPS in 2001. Those PPAs and the related rates agreed to for such facilities by the off-taker were not based upon PURPA or a QF mandated rate but were instead adopted as a result of a competitive bidding process and approved as part of the off-taker’s integrated resource planning process and in order for the off-taker to comply with Nevada’s RPS. While those PPAS were initially required to file for QF or EWG status with the FERC, the PPAs and their related prices for the term of the PPA were not approved by the FERC pursuant to PURPA. The PURPA and QF risks described above also are not likely to affect our Nevada and California based projects that have their PPAs with the SCPPA because SCPPA is not a regulated public utility under PURPA.

***The reduction or elimination of government incentives could adversely affect our business, financial condition, future results and cash flows.***

Construction and operation of our geothermal power plants and recovered energy-based power plants has benefited, and may benefit in the future, from public policies and government incentives that support renewable energy and enhance the economic feasibility of these projects in regions and countries where we operate. On August 16, 2022, the US President signed into law the Inflation Reduction Act (IRA), which contains tax incentives and other provisions that incentivize investment, development and deployment of renewable energy sources and technologies. We expect that the construction and operations of our geothermal power plants, recovered energy-based power plants, battery energy storage systems and solar PV will benefit in the future from the IRA and enhance the economic feasibility of projects in the United States.

There are additional public policy and government incentives that currently benefit and that we expect will benefit the Company in the future in countries outside of the United States as well as States within the United States. The incentives in these jurisdictions include accelerated depreciation tax benefits, rebates, mandated feed-in tariffs and other similar incentives.

The availability and continuation of these public policies and government incentives have a significant effect on the economics and viability of our development program and continued construction of new geothermal, recovered energy-based, solar PV facilities and, recently, energy storage projects. Any changes to such public policies, or any reduction in or elimination or expiration of such government incentives, could affect us in different ways. For example, any reduction in, termination or expiration of renewable portfolio standards may result in less demand for generation from our geothermal and recovered energy-based, power plants. Any reductions in, termination or expiration of other government incentives could reduce the economic viability of, and cause us to reduce, the construction of new geothermal, recovered energy-based, solar PV or any other power plants. Policies supporting or deregulating the exploration, production and use of fossil fuels may create regulatory uncertainty in the renewable energy industry. Similarly, any such changes that affect the geothermal energy industry in a manner that is different from other sources of renewable energy, such as wind or solar, may put us at a competitive disadvantage compared to businesses engaged in the development, construction and operation of renewable power projects using such other resources. Any of the foregoing outcomes could have a material adverse effect on our business, financial condition, future results, and cash flows.

***We are a holding company and our cash depends substantially on the performance of our subsidiaries and the power plants they operate, most of which are subject to restrictions and taxation on dividends and distributions.***

We are a holding company whose primary assets are our ownership of the equity interests in our subsidiaries. We conduct no other business and, as a result, we depend entirely upon our subsidiaries’ earnings and cash flow.

The agreements pursuant to which some of our subsidiaries have incurred debt restrict the ability of these subsidiaries to pay dividends, make distributions or otherwise transfer funds to us prior to the satisfaction of other obligations, including the payment of operating expenses, debt service and replenishment or maintenance of cash reserves. In the case of some of our power plants that are owned jointly with other partners, there may be certain additional restrictions on dividend distributions pursuant to our agreements with those partners. In all of the foreign countries where our existing power plants are located, dividend payments to us may also be subject to withholding taxes. Each of the events described above may reduce or eliminate the aggregate amount of cash we can receive from our subsidiaries.

***The costs of compliance with federal, state, local and foreign environmental laws and our ability to obtain and maintain environmental permits and governmental approvals required for development, construction and/or operation may result in liabilities, costs and delays in construction (as well as any fines or penalties that may be imposed upon us in the event of any non-compliance or delays with such laws or regulations) that could materially and adversely affect our business, financial condition, future results and cash flow and these liabilities and costs may increase in the future.***

Our operations are subject to extensive environmental laws, ordinances and regulations, which may cause us to incur significant costs and liabilities. These laws, ordinances and regulations can be subject to change and such change could result in increased compliance costs, the need for additional capital expenditures, or otherwise adversely affect us. In addition, our power plants are required to comply with numerous federal, state, local and foreign statutory and regulatory environmental standards and to maintain numerous environmental permits and governmental approvals required for development, construction and/or operation. We may not be able to renew, maintain or obtain all environmental permits and governmental approvals required for the continued operation or further development and construction of the power plants. We have not yet obtained certain permits and government approvals required for the completion and successful operation of power plants under development, construction or enhancement. Our failure to renew, maintain or obtain required permits or governmental approvals, including the permits and approvals necessary for operating power plants under development, construction or enhancement, could cause our operations to be limited or suspended resulting in fines under the PPA.

We may also be subject to litigation seeking to rescind or delay our receipt of environmental permits and governmental approvals. See “Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to significant liabilities and reputational damage that could have a material adverse effect on us” for additional information.

In addition, some of the environmental permits and governmental approvals that have been issued to the power plants contain conditions and restrictions, including restrictions or limits on emissions and discharges of pollutants and contaminants, or may have limited terms. If we fail to satisfy these conditions or comply with these restrictions, or with any statutory or regulatory environmental standards, we may become subject to regulatory enforcement action and the operation of the power plants could be adversely affected or be subject to fines, penalties or additional costs or other sanctions, including the imposition of investigatory or remedial obligations of the issuance of orders limiting or prohibiting our operations.

***We could be exposed to significant liability for violations of hazardous substances laws because of the use or presence of such substances at our power plants.***

Our power plants are subject to numerous domestic and foreign federal, regional, state and local statutory and regulatory standards relating to the generation, handling, transportation, use, storage, treatment and disposal of hazardous substances. We use butane, pentane, industrial lubricants, and other substances at our power plants which are or could become classified as hazardous substances. If any hazardous substances are found to have been released into the environment at or by the power plants in concentrations that exceed regulatory limits, we could become liable for the investigation and removal of those substances, regardless of their source and time of release. If we fail to comply with these laws, ordinances or regulations (or any change thereto), we could be subject to civil or criminal liability, the imposition of liens or fines, and cessation of operations, large expenditures to bring the power plants into compliance or other sanctions. Furthermore, under certain federal and states laws in the United States, we can be held liable for the cleanup of releases of hazardous substances at any of our current or former facilities or at any other locations where we arranged for disposal of those substances, even if we did not cause the release at that location or if the release complied with applicable law at the time it occurred. Liability under these laws can be joint and several. The cost of any remediation activities in connection with a spill or other release of such substances could be significant and could expose us to significant liability.

### U.S. federal, state and international income tax law changes could adversely affect us

The Company continuously monitors and examines the impact of U.S. and international tax law changes, such as the Tax Act, CARES and similar tax law changes internationally, in order to determine the impact it may have on our business. The overall impact of the global tax law changes is uncertain, and our business, financial condition, future results and cash flow, as well as our stock price, could be adversely affected.

***Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to significant liabilities and reputational damage that could have a material adverse effect on us.***

We are involved in the ordinary course of business and otherwise in a number of lawsuits involving, among other matters, employment, commercial, and environmental issues, and other claims for injuries and damages, including the lawsuit filed by the Center for Biological Diversity and Fallon Paiute-Shoshone Tribe on December 15, 2021 in the U.S. District Court for the District of Nevada, which seeks to revoke the BLM’s approval of the development of our Dixie Meadows geothermal power plant in Nevada on the basis that the BLM failed to adequately consider in its final environmental review the project’s impact on the tribe’s interests in performing traditional religious practices and the habitat of a species of toad native to the area. We evaluate litigation claims and legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Based on these evaluations and estimates, when required by applicable accounting rules, we establish reserves and disclose the relevant litigation claims or legal proceedings, as appropriate. These evaluations and estimates are based on the information available to management at the time and involve a significant amount of judgment. Actual outcomes or losses may differ materially from current evaluations and estimates. The settlement or resolution of such claims or proceedings may have a material adverse effect on us. We use appropriate means to contest litigation threatened or filed against us, but the litigation environment poses a significant business risk.

We are also involved in the ordinary course of business in regulatory investigations and other administrative proceedings, and we are exposed to the risk that we may become the subject of additional regulatory investigations or administrative proceedings. For example, we are providing information to the SEC and Department of Justice ("DOJ") related to their investigation into certain claims made in a report published by a short seller regarding the Company’s compliance with anti-corruption laws and formed a Special Committee of independent directors, which worked with outside legal counsel to investigate the claims made.

### Risks Related to Economic and Financial Conditions

***We may be unable to obtain the additional financing we need to pursue our growth strategy and any future financing we receive may be less favorable to us than our current financing arrangements, either of which may adversely affect our ability to expand our operations.***

Some of our geothermal power plants have been financed using leveraged financing structures, consisting of non-recourse or limited recourse debt obligations. Each of our projects under development or construction and those projects and businesses we may seek to acquire, or construct will require substantial capital investment. Our continued access to capital on acceptable or favorable terms to us is necessary for the success of our growth strategy, particularly in enhancing our portfolio through M&A activities. Our attempts to obtain future financings may not be successful or on favorable terms.

In recent years, we have also increased our corporate recourse debt at the holding company level due to our ability to obtain improved economic terms, and in June 2022 we issued, $431.25 million aggregate principal amount of 2.50% convertible senior notes due 2027, which we refer to as the “Notes”. Our existing and any future indebtedness may make it more difficult for us to refinance or borrow additional funds in the future, limiting our ability to pursue our growth strategy.

Market conditions and other factors may not permit future project and acquisition financings on terms similar to those our subsidiaries have previously received. Our ability to arrange for financing on a substantially non-recourse or limited recourse basis, and the costs of such financing, are dependent on numerous factors, including general economic conditions, conditions in the global capital and credit markets, investor confidence, the continued success of current power plants, the credit quality of the power plants being financed, the political situation in the country where the power plant is located, and the continued existence of tax and securities laws which are conducive to raising capital. If we are not able to obtain financing for our power plants on a substantially non-recourse or limited recourse basis, we may have to finance them using recourse capital such as direct equity investments or the incurrence of additional debt by us.

Also, in the absence of favorable financing options, we may decide not to build new plants or acquire facilities from third parties. Any of these alternatives could have a material adverse effect on our growth prospects.

We may also need additional financing to implement our strategic plan. For example, our cash flow from operations and existing liquidity facilities may not be adequate to finance any acquisitions we may want to pursue or new technologies we may want to develop or acquire. Financing for acquisitions or technology development activities may not be available on the non-recourse or limited recourse basis we have historically used for our business, or on other terms we find acceptable.

***Our debt obligations may adversely affect our ability to raise additional capital and will be a burden on our future cash resources, particularly if we elect to settle these obligations in cash upon conversion or upon maturity or required repurchase.***

Our ability to meet our payment obligations under the Note, depends on our future cash flow performance. This, to some extent, is subject to general economic, financial, competitive, legislative and regulatory factors, as well as other factors that may be beyond our control. There can be no assurance that our business will generate positive cash flow from operations, or that additional capital will be available to us, in an amount sufficient to enable us to meet our debt payment obligations and to fund other liquidity needs. If we are unable to generate sufficient cash flow to service our debt obligations, we may need to refinance or restructure our debt, sell assets, reduce or delay capital investments, or seek to raise additional capital. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at such time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations. As a result, we may be more vulnerable to economic downturns, less able to withstand competitive pressures and less flexible in responding to changing business and economic conditions.

***Our foreign power plants and foreign manufacturing operations expose us to risks related to fluctuations in currency rates, which may reduce our profits from such power plants and operations.***

Risks attributable to fluctuations in currency exchange rates can arise when any of our foreign subsidiaries incur operating or other expenses in one type of currency but receive revenues in another. In such cases, an adverse change in exchange rates can reduce such subsidiary’s ability to meet its debt service obligations, reduce the amount of cash and income we receive from such foreign subsidiary or increase such subsidiary’s overall expenses. In addition, the imposition by foreign governments of restrictions on the transfer of foreign currency abroad, or restrictions on the conversion of local currency into foreign currency, would have an adverse effect on the operations of our foreign power plants and foreign manufacturing operations, and may limit or diminish the amount of cash and income that we receive from such foreign power plants and operations.

***Our power plants have generally been financed through a combination of our corporate funds and limited or non-recourse project finance debt and lease financing. If our project subsidiaries default on their obligations under such limited or non-recourse debt or lease financing, we may be required to make certain payments to the relevant debt holders, and if the collateral supporting such leveraged financing structures is foreclosed upon, we may lose certain of our power plants.***

Our power plants have generally been financed using a combination of our corporate funds and limited or non-recourse project finance debt or lease financing. Limited recourse project finance debt refers to our additional agreement, as part of the financing of a power plant, to provide limited financial support for the power plant subsidiary in the form of limited guarantees, indemnities, capital contributions and agreements to pay certain debt service deficiencies. Non-recourse project finance debt or lease financing refers to financing arrangements that are repaid solely from the power plant’s revenues and are secured by the power plant’s physical assets, major contracts, cash accounts and, in many cases, our ownership interest in the project subsidiary. If our project subsidiaries default on their obligations under the relevant debt documents, creditors of a limited recourse project financing will have direct recourse to us, to the extent of our limited recourse obligations, which may require us to use distributions received by us from other power plants, as well as other sources of cash available to us, in order to satisfy such obligations. In addition, if our project subsidiaries default on their obligations under the relevant debt documents (or a default under such debt documents arises as a result of a cross-default to the debt documents of some of our other power plants) and the creditors foreclose on the relevant collateral, we may lose our ownership interest in the relevant project subsidiary or our project subsidiary owning the power plant would only retain an interest in the physical assets, if any, remaining after all debts and obligations were paid in full.

***Possible fluctuations in the cost of construction, raw materials, commodities and drilling may materially and adversely affect our business, financial condition, future results, and cash flow.***

Our manufacturing operations are dependent on the supply of various raw materials, including primarily steel and aluminum, commodities, vessels and industrial equipment components that we use. We currently obtain all such raw materials, commodities and equipment at prevailing market prices. We are not dependent on any one supplier and do not have any long-term agreements with any of our suppliers. Global events such as COVID-19 resulted in a shutdown of certain businesses at the beginning of the outbreak, which have since reopened, and resulted in delays in the supply and cost increase of raw materials and components that we purchased for our equipment manufacturing and in the cost increase of marine and other transportation, which delays and cost increases are beginning to moderate. Additionally, Russia’s ongoing invasion of and military attacks on Ukraine, including indirect impacts as a result of sanctions and economic disruption, has complicated and may continue to further complicate existing supply chain constraints. Our development activity is also impacted by the supply delay and cost increase of storage batteries and Solar PV panels. Further cost increases of such raw materials, commodities and equipment could adversely affect our profit margins.

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

We enter, from time to time, into commodity derivative contracts to manage our price exposure to our energy storage segment revenue. While these transactions are intended to limit our exposure to the adverse effects of fluctuations of storage services prices, they may also limit our ability to benefit from favorable changes in market conditions, and may subject us to periodic earnings volatility in the instances where we do not seek hedge accounting for these transactions or if the correlation between the hedge and the actual performance of the asset will be lower. Also, in connection with such derivative transactions, we may be required to make cash payments to maintain margin accounts and to settle the contracts at their value upon termination.

Finally, this activity exposes us to potential risk of counterparties to our derivative contracts failing to perform under the contracts. As a result, the effectiveness of our risk management could have an impact on our business, results of operations and cash flows.

***We have incurred substantial indebtedness that may decrease our business flexibility, access to capital, and/or increase our borrowing costs, and we may still incur substantially more debt, which may adversely affect our operations and financial results.***

In June 2022, we issued $431.25 million aggregate principal amount of 2.50% convertible senior notes due 2027, which we refer to as the Notes. As of December 31, 2022, we had $431.3 million outstanding aggregate principal amount of Notes. Our indebtedness may limit our ability to borrow additional funds for working capital, capital expenditures, acquisitions or other general business purposes, limit our ability to use our cash flow or obtain additional financing for future working capital, capital expenditures, acquisitions or other general business purposes, require us to use a substantial portion of our cash flow from operations to make debt service payments, limit our flexibility to plan for, or react to, changes in our business and industry, place us at a competitive disadvantage compared to our less leveraged competitors and increase our vulnerability to the impact of adverse economic and industry conditions.

***We may issue additional shares of our common stock in connection with conversions of the Notes, and thereby dilute our existing stockholders and potentially adversely affect the market price of our common stock.***

In the event that the Notes are converted and the conversion value exceeds $1,000 per $1,000 principal amount of Notes, the ownership interests of existing stockholders will be diluted, and any sales in the public market of any shares of our common stock issuable upon such conversion could adversely affect the prevailing market price of our common stock. In addition, the anticipated conversion of the Notes could depress the market price of our common stock.

***The fundamental change provisions of the Notes may delay or prevent an otherwise beneficial takeover attempt of us.***

If the Company undergoes a “fundamental change”, subject to certain conditions, holders may require the Company to repurchase for cash all or part of their Notes at a fundamental change repurchase price equal to 100% of the principal amount of the Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the fundamental change repurchase date. In addition, if such fundamental change also constitutes a “make-whole fundamental change”, the conversion rate for the Notes may be increased upon conversion of the Notes in connection with such “make-whole fundamental change”. Any increase in the conversion rate will be determined based on the date on which the “make-whole fundamental change” occurs or becomes effective and the price paid (or deemed paid) per share of our common stock in such transaction. Any such increase will be dilutive to our existing stockholders. Our obligation to repurchase the Notes or increase the conversion rate upon the occurrence of a make-whole fundamental change may, in certain circumstances, delay or prevent a takeover of us that might otherwise be beneficial to our stockholders.

***The Capped Call Transactions may affect the value of the Notes and our common stock.***

In connection with the issuance of the Notes, we entered into Capped Call Transactions with certain financial institutions. The Capped Call Transactions are expected generally to reduce or offset the potential dilution upon conversion of the Notes and/or offset any cash payments we are required to make in excess of the principal amount of converted Notes, as the case may be, with such reduction and/or offset subject to a cap.

From time to time, certain financial institutions (with which we entered into the Capped Call Transactions) or their respective affiliates may modify their hedge positions by entering into or unwinding various derivatives with respect to our common stock and/or purchasing or selling our common stock or other securities of ours in secondary market transactions prior to the maturity of the Notes. This activity could also cause or avoid an increase or a decrease in the market price of our common stock.

The potential effect, if any, of these transactions and activities on the price of our common stock or Notes will depend in part on market conditions and cannot be ascertained at this time. Any of these activities could adversely affect the value of our common stock.

***We are subject to counterparty risk with respect to the Capped Call Transactions.***

All or some of the financial institutions (which are counterparties to the capped call transactions) might default under the Capped Call Transactions. Our exposure to the credit risk of the counterparties will not be secured by any collateral. Past global economic conditions have resulted in the actual or perceived failure or financial difficulties of many financial institutions. If an option counterparty becomes subject to insolvency proceedings, we will become an unsecured creditor in those proceedings with a claim equal to our exposure at the time under the capped call transactions with such option counterparty. Our exposure will depend on many factors but, generally, an increase in our exposure will be correlated to an increase in the market price and in the volatility of our common stock. In addition, upon a default by an option counterparty, we may suffer adverse tax consequences and more dilution than we currently anticipate with respect to our common stock. We can provide no assurance as to the financial stability or viability of the option counterparties.

***We are exposed to swap counterparty credit risk that could materially and adversely affect our business, operating results, and financial condition.***

We rely on cross-currency swap contracts to effectively manage our currency risk related to our Senior Unsecured Bonds - Series 4 issued in July 2020. Failure of any of our counterparties to perform under derivatives contracts could disrupt our hedging operations if the counterparties do not fulfill their obligations under the agreements, particularly if we were entitled to a termination payment under the terms of the contract that we did not receive, if we had to make a termination payment upon default of the counterparty, or if we were unable to reposition the swap with a new counterparty.

***We may not be able to obtain sufficient insurance coverage to cover damages resulting from any damages to our assets and profitability including but not limited to natural disasters such as volcanic eruptions, lava flows, wind and earthquake, which could materially and adversely affect our business, operating results, and financial condition.***

We maintain physical damage and business interruption insurance however, our business interruption and property damage insurance coverage may not be sufficient to cover all losses sustained as a result of natural disasters such as flood, volcanic eruptions, lava flows, wind and earthquake or any other insurable risk. In addition, insurance coverage may not continue to be available in the future at rates that we believe are reasonable or in amounts of coverage or with scope of coverage adequate to insure against future natural disasters. Following the May 2018 eruption of the Kilauea volcano in Hawaii, the full amount of our insurance claim for damages to our Puna power plant was denied and we experienced increased costs and difficulties in obtaining sufficient insurance coverage for natural disasters. Before the eruption in 2018, we obtained natural disasters business interruption and property damage insurance coverage of up to approximately $100 million compared to $30 million, with portions of the risk self-insured, secured in 2022 and 2023. An inability to obtain sufficient and adequate insurance to cover all book net equity may cause us to self-insure some or all of a particular location and losses, causing us to experience higher than expected insurance costs.

If insurance premiums or deductibles were to increase in the future, if certain types of insurance coverage were to become unavailable or cost prohibitive, if we were to have to increase the percentage of our self-insured insurance coverage or if we were to experience losses in excess of, or outside the scope of, our insurance coverage, such additional costs could have a material adverse effect on our business, financial condition, results of operations and cash flows.

### Risks Related to Force Majeure

***Risks relating to public health epidemics, including the ongoing COVID-19 pandemic, have had, and may continue to have, an adverse impact on our business and financial results.***

We face various risks relating to public health issues, including epidemics, pandemics, and other outbreaks, including the ongoing COVID-19 pandemic. The effects and potential effects of COVID-19 include, but are not limited to:

delays in permitting, its impact on general economic conditions, trade and financing markets, adverse impacts on customers’ purchasing decisions, reduction in the demand for electricity and for our products, supply chain difficulties, an increase in the cost of raw materials, and significant uncertainty in the overall continuity in business operations. Also, the economics of some of projects may impacted by the rising inflation as the energy rate at some of our U.S. PPAs is not tied to CPI and has no escalation. We continue to monitor closely the impact of COVID-19 on all aspects of our business and geographies, including its impact on our employees, customers, and suppliers. The extent to which the COVID-19 pandemic may continue to affect our business will depend on continued developments, such as the emergence of new variants and status of governmental measures to combat it, which are uncertain and cannot be predicted. Even after the COVID-19 pandemic has subsided, we may continue to suffer an adverse effect on our business due to possible longer-term global economic effects of COVID-19, including any economic recession. In addition, a resurgence of COVID-19 cases or an emergence of additional variants or strains could cause other widespread or more severe impacts depending on where infection rates are highest.

In addition, the impact of COVID-19 on macroeconomic conditions may impact the proper functioning of financial and capital markets, foreign currency exchange rates, commodity and interest rates. Any of the events described above could amplify the other risks and uncertainties described in this report and could materially adversely affect our business, financial condition, results of operations and/or stock price.

***The existence of a prolonged force majeure event or a forced outage affecting a power plant, or the transmission systems could reduce our net income and materially and adversely affect our business, financial condition, future results and cash flow.***

The operation of our subsidiaries’ geothermal power plants is subject to a variety of risks, including events such as fires, explosions, earthquakes, landslides, floods, severe storms, volcanic eruptions, lava flow or other similar events. If a power plant experiences an occurrence resulting in a force majeure event, although our subsidiary that owns that power plant would be excused from its obligations under the relevant PPA, the relevant power purchaser may not be required to make any capacity and/or energy payments with respect to the affected power plant for as long as the force majeure event continues and, pursuant to certain of our PPAs, will have the right to prematurely terminate the PPA. Additionally, to the extent that a forced outage has occurred, and if as a result the power plant fails to attain certain performance requirements under certain of our PPAs, the power purchaser may have the right to permanently reduce the contract capacity (and correspondingly, the amount of capacity payments due pursuant to such agreements in the future), seek refunds of certain past capacity payments, and/or prematurely terminate the PPA. As a consequence, we may not receive any net revenues from the affected power plant other than the proceeds from any business interruption insurance that applies to the force majeure event or forced outage after the relevant waiting period and may incur significant liabilities in respect of past amounts required to be refunded.

On May 3, 2018, the Kilauea volcano located in close proximity to our Puna 38 MW geothermal power plant in the Puna district of Hawaii's Big Island erupted following a significant increase in seismic activity in the area. The lava ultimately covered the wellheads of three geothermal wells, monitoring wells and the substation of the Puna complex and an adjacent warehouse that stored a drilling rig that was also consumed by the lava. We resumed operations and the Puna power plant is operating at approximately 23- 25 MW.

In addition to our power plant in Puna, Hawaii, our power plant in Amatitlan, Guatemala is located in proximity to an active volcano. As a result of recent events impacting our Puna facility, we cannot be certain how investors will assess the risks to which our facilities are subject and whether this assessment will adversely impact perceptions of our business and our share price.

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

Our operations and facilities, in particular, our generation and transmission facilities, information technology systems and other infrastructure facilities, systems and physical assets that we acquire, construct or develop, as well as those of third parties on which we rely, may be targets of terrorist acts and threats, as well as events occurring in response to or in connection with them, that could cause environmental repercussions, result in full or partial disruption of our operations. These operations and facilities are also subject to natural disasters, public health crises, fire, power loss and telecommunication failures. Any of our assets or those of third-party vendors could be directly or indirectly affected by such events or activities. Any such terrorist acts, environmental repercussions or disruptions or natural disasters could result in a significant decrease in revenues or significant reconstruction or remediation costs, beyond what could be recovered through insurance policies, which could have a material adverse effect on the business, financial condition, results of operations and cash flows.

### Risks Related to Ownership of Our Common Stock

***Future equity issuances, including through our current or any future equity compensation plans, could result in dilution, which could cause the price of our shares of common stock to decline.***

We may issue additional shares of our common stock in the future pursuant to current or future equity compensation plans, upon conversions of preferred stock or debt, including the Notes, or in connection with future acquisitions or financings. We may also seek to raise additional funds, finance acquisitions or develop strategic relationships by issuing additional shares of our common stock. If we choose to raise capital by selling shares of our common stock, or securities convertible into shares of our common stock, or additional shares are issued for the reasons described above or otherwise, the issuance could have a dilutive effect on the holders of our common stock and could have a material negative effect on the market price of our common stock.

***A substantial percentage of our common stock is held by stockholders whose interests may conflict with the interests of our other stockholders.***

As of December 31, 2022, ORIX holds 11.9% of our shares of common stock outstanding. Pursuant to the Governance Agreement between us and ORIX entered into in connection with this stock purchase transaction, based on its current level of ownership of our shares, ORIX has the right to designate one director to our Board for as long as ORIX and its affiliates collectively hold at least 5% of the voting power of all of our outstanding voting securities, the right to representation on certain committees of our Board as well as preemptive rights pursuant to the Governance Agreement. In addition, the Governance Agreement provides ORIX preemptive rights in the event we issue common stock or other securities that entitle the holder to vote for the election of directors. ORIX may also exercise certain registration rights pursuant to the Registration Rights Agreement, as amended, between us and ORIX.

As a result of these rights and ORIX’s beneficial ownership of our common stock, ORIX could exert influence through its Board representation on our and our subsidiaries’ business, operations and management, including our strategic plans, or, as a significant stockholder, on matters submitted to a vote of our stockholders, including mergers, consolidations and the sale of all or substantially all of our assets. This concentration of ownership of our common stock could delay or prevent proxy contests, mergers, tender offers, or other purchases of our common stock that might otherwise give our stockholders the opportunity to realize a premium over the then-prevailing market price for our shares. If ORIX requires us to register for sale the common stock held by ORIX or ORIX otherwise sells its common stock in the public markets, the price of our common stock may decline. This concentration of ownership may also adversely affect the liquidity of our common stock.

***The price of our common stock may fluctuate substantially, and your investment may decline in value.***

The market price of our common stock may be highly volatile and may fluctuate substantially due to many factors, including:

- actual or anticipated fluctuations in our results of operations including as a result of seasonal variations in our Electricity segment-based revenues or variations from year-to-year in our Product segment-based revenues;
- variance in our financial performance from the expectations of market analysts;
- conditions and trends in the end markets we serve, and changes in the estimation of the size and growth rate of these markets;
- our ability to integrate acquisitions;
- announcements of significant contracts by us or our competitors;
- changes in our pricing policies or the pricing policies of our competitors;
- restatements of historical financial results and changes in financial forecasts;
- loss of one or more of our significant customers;
- legislation;
- changes in market valuation or earnings of our competitors;
- the trading volume of our common stock;
- the trading of our common stock on multiple trading markets, which takes place in different currencies and at different times; and
- general economic conditions.

In addition, the stock market in general, and the NYSE and the market for energy companies in particular, have experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of particular companies affected. These broad market and industry factors may materially harm the market price of our common stock, regardless of our operating performance. In the past, following periods of volatility in the market price of a company’s securities, securities class-action litigation has often been instituted against that company. Such litigation, if instituted against us could result in substantial costs and a diversion of management’s attention and resources, which could materially harm our business, financial condition, future results and cash flow. We are generally obliged under our bylaws, to the extent permitted under Delaware law, to indemnify our current and former officers who are named as defendants in these types of lawsuits. While a certain amount of insurance coverage is available for expenses or losses associated with these lawsuits, this coverage may not be sufficient for certain litigation. For information on our recently dismissed and ongoing securities class actions, see “Commitments and Contingencies” in Note 21 to the consolidated financial statements contained in Item 8 of this Annual Report.

## Properties

As filed, 851 characters.

We currently own our corporate offices at 6140 Plumas Street in Reno, Nevada 89519. We also occupy an approximately 807,000 square foot office and manufacturing facility located in the Industrial Park of Yavne, Israel, which we lease from the Israel Land Administration. See Item 13 — “Certain Relationships and Related Transactions”. In Turkey, we established and leased a facility to locally produce power plant components to our local customers.

We believe that our current offices and manufacturing facilities will be adequate for our operations as currently conducted.

Each of our power plants is located on property leased or owned by us or one of our subsidiaries or is a property that is subject to a concession agreement.

Information and descriptions of our plants and properties are included in Item 1 — “Business”, of this Annual Report.

## Legal proceedings

As filed, 236 characters.

The information required with respect to this item can be found under “Commitments and Contingencies” in Note 21 of the consolidated financial statements contained in Item 8 of this Annual Report and is incorporated by reference herein.

## Management's discussion and analysis

As filed, 110,089 characters.

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

### General

### Overview of Fiscal Year 2022 Revenues

### Recent Developments

The most significant recent developments for our Company and business during 2022 and 2023 to date are described below.

- In January 2023, we, together with PT Medco Power Indonesia (“Medco Power”), signed a Financing Agreement with PT Sarana Multi Infrastruktur (Persero) (“SMI”) for development of the Ijen Geothermal Power Plant. The Ijen power plant will be developed in stages and the first phase of development is expected to generate 34 MW in 2025. MCG, a jointly owned company between Medco Power (51% equity share) and Ormat Technologies (49% equity share), will develop and operate the first geothermal power plant in East Java. Ormat also signed a contract as a key contractor on OEC supply for this project and secured $32.1 million to our backlog.
- In December 2022, we entered into a partnership agreement with a private investor, under which the private investor acquired membership interests in the CD4 Geothermal power plant project for an initial purchase price of approximately $50.3 million and for which it will pay additional installments that are expected to amount to approximately $7.3 million. The Company will continue to operate and maintain the power plant and will receive substantially all the distributable cash flow generated by the power plant, and the private investor receives substantially 99% of the tax attributes of the project.
- In November 2022, one of our subsidiaries entered into a note purchase agreement with the Prudential Insurance Company of America and other noteholders, pursuant to which we issued approximately $61.6 million in aggregate principal amount of senior secured notes. Proceeds of the notes were used to refinance the Prudential Capital Group - Idaho non-recourse loan, which had a remaining balance of approximately $16.0 million due in full in March 2023. For further details see discussion under Item 8 - Financial Statement and Supplementary Data.
- In October 2022, we signed a fixed price 15-year Energy Storage Power Purchase Agreement (ESPPA) with San Diego Gas & Electric (SDG&E) for the 80MW (320MWH) Bottleneck Battery Energy Storage System (BESS) located in the Central Valley of California. The ESPPA was recently approved by the CPUC. This project, once in operation, is expected to increase 2022 revenues in our battery storage segment by 50%.
- In August 2022, we signed with Contact Energy of New Zealand an EPC contract for a new maximum continuous performance 59MW geothermal power plant in New Zealand and signed a 6MW supply contract with Sarulla Operations Ltd. in Indonesia. The combined expected revenue of the two contracts is approximately $100 million.
- In July 2022, we announced the commercial operation of the CD4 30 MW geothermal power plant. The CD4 facility provides 7 MW of geothermal power to two Community Choice Aggregators, Silicon Valley Clean Energy and Central Coast Community Energy, each under a 10-year power purchase agreement (“PPA”), with a total of 14MW. In addition, the facility provides 16 MW of geothermal power to the Southern California Public Power Authority ("SCPPA") under a 25-year agreement.
- In July 2022, we completed two Solar PV power plants: (1) the 5 MW Steamboat Hills Solar plant in Nevada that is used for the ancillary needs of the Steamboat Hills geothermal power plant and will free a similar amount of MW to be sold from the geothermal resource to SCPPA under the SCPPA portfolio PPA; and (2) the 20MW Wister power plant in California that sells power under a long-term contract with San Diego Gas & Electric.
- In June 2022, the Company issued $375.0 million aggregate principal amount of its 2.5% convertible senior notes due 2027 (the “Notes”). The Notes were offered and sold in a private offering to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended, pursuant to an indenture between the Company and U.S. Bank National Association, as trustee. Additionally, the Company granted the initial purchasers an option to purchase up to an additional $56.25 million aggregate principal amount of the Notes. The initial purchasers executed their option on June 27, 2022, thereby increasing the total aggregated principal amount of the Notes issued to $431.25 million. The Notes will mature on July 15, 2027, unless earlier converted, redeemed or repurchased. Interest will accrue on the Notes at a rate of 2.50% per year and will be payable semiannually in arrears on January 15 and July 15 of each year, beginning on January 15, 2023.
- In June 2022, we announced the commercial operation of the 5 MW/20 MWh Tierra Buena Battery Energy Storage System (Tierra Buena BESS). The Tierra Buena BESS will provide local resource adequacy to two Community Choice Aggregators (CCAs), Redwood Coast Energy Authority and Valley Clean Energy, at 2.5 MW each, under 10-year agreements. In addition, the facility will provide ancillary services and energy optimization through participation in merchant markets run by the California Independent System Operator (CAISO). The facility will connect to the adjacent Pacific Gas & Electric distribution circuit.
- In June 2022, we paid $221.9 million to prepay our senior unsecured Series 3 Bonds. The payment included the outstanding amount that was due in September 2022 and the interest related to the prepayment make-whole.
- In June 2022, we announced the execution of a PPA with California Community Power (CC Power), a Joint Powers Agency consisting of numerous CCAs. Energy deliveries under the portfolio PPA are expected to start in the second quarter of 2024, with the expectation that the entire portfolio covered under the new PPA will be online by the end of 2026. The portfolio PPA covers up to 125MW for a term of 20 years and is comprised entirely of new projects currently under construction or in development in Nevada and California. Capacity is subject to CAISO connection approval.
- In May 2022, we announced the execution of two PPAs with NV Energy. Under the first PPA, signed in 2021, NV Energy will purchase 25 MW of power over 25 years generated by the North Valley Geothermal Project, a new facility expected to come online by early 2023. Additionally, NV Energy will purchase up to 135 MW of power generated by a portfolio of the Company's new and existing geothermal power plants under a PPA signed in May. The portfolio PPA is subject to Public Utility Commission’s approval.
- In April 2022, we commenced the commercial operation of the Tungsten Mountain 2 geothermal power plant, which sells an additional 13 MW to the Southern California Public Power Authority ("SCPPA") under the SCPPA portfolio PPA. The addition of Tungsten Mountain 2 to our existing Tungsten geothermal power plant increased our total Tungsten complex geothermal capacity to 42 MW.
- In March 2022, we signed a 15-year PPA with Peninsula Clean Energy, a CCA that provides more than 3,500 GWh of electricity to San Mateo County and the City of Los Banos in California. Under the terms of the PPA, Peninsula Clean Energy will purchase 26 MW of clean, renewable energy from Ormat’s Heber 2 geothermal facility located in Imperial Valley, CA. This PPA marks the successful completion of Ormat’s first ever solicitation for bids, with a request for bids (RFB) on the Heber 2 facility issued in July of 2021.
- Our 40 MW Heber 1 geothermal power plant located in California experienced an outage following a fire on February 25, 2022, that caused damage to the steam turbine-generator area. The Heber 1 power plant is part of the 81 MW Heber complex and sells its electricity under a long-term contract with the Southern California Public Power Authority. We decided not to rebuild the Heber 1 power plant and received all relevant insurance proceeds related to the event. We are currently optimizing the Heber complex through the repowering, which is expected to be completed in the second quarter of 2023.

### Opportunities, Trends and Uncertainties

Different trends, factors and uncertainties may impact our operations and financial condition, including many that we do not or cannot foresee. However, we believe that our results of operations and financial condition for the foreseeable future will be primarily affected by the following trends, factors and uncertainties that are from time to time also subject to market cycles, in addition to those covered under “COVID-19 Update”:

- There has been increased demand for energy generated from geothermal and other renewable resources in the United States as costs for electricity generated from renewable resources have become more competitive. Much of this is attributable to legislative and regulatory requirements and incentives, such as state RPS and federal tax credits such as PTCs or ITCs (which are discussed in more detail in the section entitled “Government Grants and Tax Benefits” below). We believe that future demand for energy generated from geothermal and other renewable resources in the United States will be driven primarily by further commitment to, and implementation of, state RPS and greenhouse gas reduction initiatives.
- The U.S. federal government has taken, and we expect it to continue to take, certain actions which are supportive of the industry for climate solutions. In August 2022, the President of the United States signed into law the IRA of 2022. The IRA includes several tax incentives to promote climate change mitigation and clean energy, electric vehicles, battery and energy storage manufacture or purchase. The U.S. presidential administration has taken immediate steps at the federal level which we believe signify support for climate solutions, including, but not limited to, rejoining the Paris Climate Accords and re-establishing a social price on carbon used in cost/benefit analysis for policy making. We expect this new administration, combined with a closely divided Congress, will usher in additional regulations supportive of the markets in which we invest.
- We expect that a variety of local governmental initiatives will create new opportunities for the development of new projects with the potential to realize higher returns on our equity as well as to create additional markets for our products. These initiatives include the award of long-term contracts to independent power generators, the creation of competitive wholesale markets for selling and trading energy, capacity and related energy products and the adoption of programs designed to encourage “clean” renewable and sustainable energy sources.
- In the Product segment, we see new opportunities for business in New Zealand, the U.S., Asia Pacific and Central and South America. We have experienced increased competition from binary power plant equipment suppliers including the major steam turbine manufacturers. While we believe that we have a distinct competitive advantage based on our technology, accumulated experience and current worldwide share of installed binary generation capacity, an increase in competition may impact our ability to secure new purchase orders from potential customers. The increased competition may also lead to further reductions in the prices that we are able to charge for our binary equipment.
- Russia’s invasion of and military attacks on Ukraine, including indirect impacts as a result of sanctions and economic disruption, has complicated and may continue to further complicate existing supply chain constraints. Supply chain constraints may cause cost increases of raw materials, commodities and equipment that could adversely affect our profit margins.
- In the markets in which we operate, particularly in the U.S, there have been higher rates of inflation over the last year. While our U.S. contracts are not indexed to inflation most of our international-based contracts are indexed to inflation. If inflation continues to increase in our markets, it may increase our expenses such that our profit margins could be adversely impacted. It may also increase the costs of some of our development projects that could negatively impact their competitiveness.
- Interest rate increases for both short-term and long-term debt have increased sharply. Although our outstanding debt mostly bears fixed interest rates, as we refinance it, or borrow additional amounts, we may incur additional interest expense versus expiring loans.

### Revenues

### Sources of Revenues

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

*Electricity Segment.* Revenues attributable to our Electricity segment are derived from the sale of electricity from our power plants pursuant to long-term PPAs. While approximately 89.1% of our Electricity revenues for the year ended December 31, 2022 were derived from PPAs with fixed price components, we have variable price PPAs in Hawaii, which provide for payments based on the local utilities’ avoided cost. The avoided cost is the incremental cost that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others. In Hawaii, the prices paid for electricity pursuant to the 25 MW PPA for the Puna Complex in Hawaii change primarily as a result of variations in the price of oil as well as other commodities. In 2019, we signed a new PPA related to Puna with fixed prices, increased capacity and extended the term until 2052. We are currently negotiating economic amendments to the PPA which are subject to PUC approval.

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

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

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

*Energy Storage Segment.* Revenues attributable to our Energy Storage segment are generated by several grid-connected BESS facilities that we own and operate from selling energy, capacity and/or ancillary services in merchant markets like PJM Interconnect, ISO New England, ERCOT and CAISO. The revenues fluctuate over time since a large portion of such revenues are generated in the merchant markets, where price volatility is inherent. We recently signed a long-term tolling agreement that will secure fixed revenues for our Bottleneck 80MW/320MWh project in California.

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

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

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

*(Dollars in thousands)*

| Revenues: | Revenues Year Ended December 31, 2022 | 2021 | 2020 | % of Revenues for Period Indicated Year Ended December 31, 2022 | 2021 | 2020 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Electricity | $631,727 | $585,771 | $541,393 | 86.0% | 88.3% | 76.8% |
| Product | 71,414 | 46,920 | 148,125 | 9.7 | 7.1 | 21.0 |
| Energy Storage | 31,018 | 30,393 | 15,824 | 4.2 | 4.6 | 2.2 |
| Total revenues | $734,159 | $663,084 | $705,342 | 100.0% | 100.0% | 100.0% |

80

### Geographic Breakdown of Results of Operations

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

*(Dollars in thousands)*

| Electricity Segment: | Revenues Year Ended December 31, 2022 | 2021 | 2020 | % of Revenues for Period Indicated Year Ended December 31, 2022 | 2021 | 2020 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| United States | $446,000 | $404,303 | $341,399 | 70.6% | 69.0% | 63.1% |
| International | 185,727 | 181,468 | 199,994 | 29.4 | 31.0 | 36.9 |
| Total | $631,727 | $585,771 | $541,393 | 100.0% | 100.0% | 100.0% |
| Product Segment: |  |  |  |  |  |  |
| United States | $7,037 | $5,414 | $5,800 | 9.9% | 11.5% | 3.9% |
| International | 64,377 | 41,506 | 142,325 | 90.1 | 88.5 | 96.1 |
| Total | $71,414 | $46,920 | $148,125 | 100.0% | 100.0% | 100.0% |
| Energy Storage Segment: |  |  |  |  |  |  |
| United States | $31,018 | $30,393 | $15,824 | 100.0% | 100.0% | 100.0% |
| International | — | — | — | — | — | — |
| Total | $31,018 | $30,393 | $15,824 | 100.0% | 100.0% | 100.0% |

In 2022, 2021 and 2020, 34%, 34% and 49% of our total revenues were derived from foreign locations, respectively, and our foreign operations had higher gross margins than our U.S. operations in each of those years. A substantial portion of international revenues came from Kenya and, to a lesser extent, from Honduras, Guadeloupe, Guatemala and other countries. Our operations in Kenya contributed disproportionately to gross profit and net income. The contribution to combined pre-tax income of our domestic and foreign operations within our Electricity segment and Product segment differ in a number of ways.

*Electricity Segment.* Our Electricity segment domestic revenues were approximately 71%, 69% and 63% of our total Electricity segment for the years ended December 31, 2022, 2021 and 2020, respectively. However, domestic operations have higher costs of revenues and expenses than our foreign operations. Our foreign power plants are located in lower-cost regions, like Kenya, Guatemala, Honduras and Guadeloupe, which favorably impact payroll, and maintenance expenses among other items. Our power plants in foreign locations are also newer than most of our domestic power plants and therefore tend to have lower maintenance costs and higher availability factors than our domestic power plants. Consequently, in 2022 and 2021, the international operations of the segment accounted for 43% and 45% of our total gross profits, 72% and 68% of our net income (assuming the majority of corporate operating expenses and financing are recorded under domestic jurisdiction) and 36% and 42% of our EBITDA, respectively.

*Product Segment.* Our Product segment foreign revenues were 90%, 88% and 96% of our total Product segment revenues for the years ended December 31, 2022, 2021 and 2020, respectively.

*Energy Storage Segment.* Our Energy Storage segment domestic revenues were 100.0% of our total Energy storage segment revenues for years ended December 31, 2022, 2021 and 2020, respectively.

### Seasonality

Electricity generation from some of our geothermal power plants is subject to seasonal variations; in the winter, our power plants produce more energy primarily attributable to the lower ambient temperature, which has a favorable impact on the energy component of our Electricity segment revenues and the prices under many of our contracts are fixed throughout the year with no time-of-use impact. The prices paid for electricity under the PPAs for the Mammoth Complex and the North Brawley power plant in California, the Raft River power plant in Idaho, the Neal Hot Springs power plant in Oregon and the recently acquired Dixie Valley power plant in Nevada, are higher in the months of June through September. The higher payments payable under these PPAs in the summer months partially offset the negative impact on our revenues from lower generation in the summer attributable to a higher ambient temperature. As a result, we expect the revenues and gross profit in the winter months to be higher than the revenues and gross profit in the summer months and in general we expect the first and fourth quarters to generate higher revenues than the second and third quarters.

### Breakdown of Cost of Revenues

### Electricity Segment

The principal cost of revenues attributable to our operating power plants are operation and maintenance expenses comprised of salaries and related employee benefits, equipment expenses, costs of parts and chemicals, costs related to third-party services, lease expenses, royalties, startup and auxiliary electricity purchases, property taxes, insurance, depreciation and amortization and, for some of our projects, purchases of make-up water for use in our cooling towers. In our California power plants, our principal cost of revenues also includes transmission charges and scheduling charges. In some of our Nevada power plants we also incur transmission and wheeling charges. Some of these expenses, such as parts, third-party services and major maintenance, are not incurred on a regular basis. This results in fluctuations in our expenses and our results of operations for individual power plants from quarter to quarter. Payments made to government agencies and private entities on account of site leases where power plants are located are included in cost of revenues. Royalty payments, included in cost of revenues, are made as compensation for the right to use certain geothermal resources and are paid as a percentage of the revenues derived from the associated geothermal rights. Royalties constituted approximately 4.8% and 4.3% of Electricity segment revenues for the years ended December 31, 2022 and 2021, respectively.

### Product Segment

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

### Energy Storage Segment

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

### Critical Accounting Estimates and Assumptions

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

- *Revenues and Cost of Revenues.* Revenues generated from the construction of geothermal and recovered energy-based power plant equipment and other equipment on behalf of third parties (Product revenues) are recognized using the percentage of completion method, which requires estimates of future costs over the full term of product delivery. Such cost estimates are made by management based on prior operations and specific project characteristics and designs. If management’s estimates of total estimated costs with respect to our Product segment are inaccurate, then the percentage of completion is inaccurate resulting in an over- or under-estimate of revenue and gross margin. As a result, we review and update our cost estimates on significant contracts on a quarterly basis, and at least on an annual basis for all others, or when circumstances change and warrant a modification to a previous estimate. Changes in job performance, job conditions, and estimated profitability, including those arising from the application of penalty provisions in relevant contracts and final contract settlements, may result in revisions to costs and revenues and are recognized in the period in which the revisions are determined. Provisions for estimated losses relating to contracts are made in the period in which such losses are determined. Revenues generated from engineering and operating services and sales of products and parts are recorded once the service is provided or product delivered as the customer obtains control of the asset, as applicable.
- *Property, Plant and Equipment.* We capitalize all costs associated with the acquisition, development and construction of power plant facilities. Major improvements are capitalized and repairs and maintenance (including major maintenance) costs are expensed. We estimate the useful life of our power plants to range between 25 and 30 years. Such estimates are made by management based on factors such as prior operations, the terms of the underlying PPAs, geothermal resources, the location of the assets and specific power plant characteristics and designs. Changes in such estimates could result in useful lives which are either longer or shorter than the depreciable lives of such assets. We periodically re-evaluate the estimated useful life of our power plants and revise the remaining depreciable life on a prospective basis. We capitalize costs incurred in connection with the exploration and development of geothermal resources beginning when we acquire land rights to the potential geothermal resource. Prior to acquiring land rights, we make an initial assessment that an economically feasible geothermal reservoir is probable on that land using available data and external assessments vetted through our exploration department and occasionally outside service providers. Costs incurred prior to acquiring land rights are expensed. It normally takes two to three years from the time we start active exploration of a particular geothermal resource to the time we have an operating production well, assuming we conclude the resource is commercially viable. In most cases, we obtain the right to conduct our geothermal development and operations on land owned by the BLM, various states or with private parties. Once we acquire land rights to the potential geothermal resource, we perform additional activities to assess the commercial viability of the resource. Such activities include, among others, conducting surveys and other analysis, obtaining drilling permits, creating access roads to drilling sites, and exploratory drilling which may include temperature gradient holes and/or slim holes. Such costs are capitalized and included in construction-in-process. Once our exploration activities are complete, we finalize our assessment as to the commercial viability of the geothermal resource and either proceed to the construction phase for a power plant or abandon the site. If we decide to abandon a site, all previously capitalized costs associated with the exploration project are written off. Our assessment of economic viability of an exploration project involves significant management judgment and uncertainties as to whether a commercially viable resource exists at the time we acquire land rights and begin to capitalize such costs. As a result, it is possible that our initial assessment of a geothermal resource may be incorrect and we will have to write off costs associated with the project that were previously capitalized. Due to the uncertainties inherent in geothermal exploration, historical impairments may not be indicative of future impairments. Included in construction-in-process are costs related to projects in exploration and development of $95.3 million and $50.7 million at December 31, 2022 and 2021, respectively.
- *Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of*. We evaluate long-lived assets, such as property, plant and equipment and construction-in-process for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Factors which could trigger an impairment include, among others, significant underperformance relative to historical or projected future operating results, significant changes in our use of assets or our overall business strategy, negative industry or economic trends, a determination that an exploration project will not support commercial operations, a determination that a suspended project is not likely to be completed, a significant increase in costs necessary to complete a project, legal factors relating to our business or when we conclude that it is more likely than not that an asset will be disposed of or sold. We test our operating plants that are operated together as a complex for impairment at the complex level because the cash flows of such plants result from significant shared operating activities. For example, the operating power plants in a complex are managed under a combined operation management generally with one central control room that controls all of the power plants in a complex and one maintenance group that services all of the power plants in a complex. As a result, the cash flows from individual plants within a complex are not largely independent of the cash flows of other plants within the complex. We test for impairment of our operating plants which are not operated as a complex, as well as our projects under exploration, development or construction that are not part of an existing complex, at the plant or project level. To the extent an operating plant becomes part of a complex in the future, we will test for impairment at the complex level.

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

If our assets are considered to be impaired, the impairment to be recognized is the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. We believe that for the year ended December 31, 2022, except for the non-cash impairment charge related to our Brawley power plant, as further detailed under Note 9 to the consolidated financial statements, no impairment exists for any of our long-lived assets; however, estimates as to the recoverability of such assets may change based on revised circumstances. Estimates of the fair value of assets require estimating useful lives and selecting a discount rate that reflects the risk inherent in future cash flows.

- *Goodwill.* Goodwill represents the excess of the fair value of consideration transferred in the business combination transactions over the fair value of tangible and intangible assets acquired, net of the fair value of liabilities assumed and the fair value of any noncontrolling interest in the acquisitions. Goodwill is not amortized but rather subject to a periodic impairment testing on an annual basis, which the Company performs on December 31 of each year, or if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount. Additionally, it is permitted to first assess qualitative factors to determine whether a quantitative goodwill impairment test is necessary. Further testing is only required if the entity determines, based on the qualitative assessment, that it is more likely than not that a reporting unit’s fair value is less than its carrying amount. Otherwise, no further impairment testing is required. An entity has the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to the quantitative goodwill impairment test. This would not preclude the entity from performing the qualitative assessment in any subsequent period. The quantitative assessment compares the fair value of the reporting unit to its carrying value, including goodwill. Under ASU 2017-04, Intangibles – Goodwill and Other (Topic 350), an entity should recognize an impairment charge for the amount by which the carrying amount of the reporting unit exceeds its fair value. However, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit.
- *Obligations Associated with the Retirement of Long-Lived Assets.* We record the fair market value of legal liabilities related to the retirement of our assets in the period in which such liabilities are incurred. These liabilities include our obligation to plug wells upon termination of our operating activities, the dismantling of our power plants upon cessation of our operations, and the performance of certain remedial measures related to the land on which such operations were conducted. When a new liability for an asset retirement obligation is recorded, we capitalize the costs of such liability by increasing the carrying amount of the related long-lived asset. Such liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. At retirement, we either settle the obligation for its recorded amount or report either a gain or a loss with respect thereto. Estimates of the costs associated with asset retirement obligations are based on factors such as prior operations, the location of the assets and specific power plant characteristics. We review and update our cost estimates periodically and adjust our asset retirement obligations in the period in which the revisions are determined. If actual results are not consistent with our assumptions used in estimating our asset retirement obligations, we may incur additional losses that could be material to our financial condition or results of operations.
- *Accounting for Income Taxes.* Significant estimates are required to arrive at our consolidated income tax provision. This process requires us to estimate our actual current tax exposure and to make an assessment of temporary differences resulting from different treatments of items for tax and accounting purposes. Such differences result in deferred tax assets and liabilities which are included in our consolidated balance sheets. For those jurisdictions where the projected operating results indicate that realization of our net deferred tax assets is not more likely than not, a valuation allowance is recorded.

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

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

### New Accounting Pronouncements

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

### Results of Operations

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

*(Dollars in thousands, except earnings per share data)*

| Revenues: | Year Ended December 31, 2022 | 2021 | 2020 |
| --- | ---: | ---: | ---: |
| Electricity | $631,727 | $585,771 | $541,393 |
| Product | 71,414 | 46,920 | 148,125 |
| Energy storage | 31,018 | 30,393 | 15,824 |
| Total revenues | 734,159 | 663,084 | 705,342 |
| **Cost of revenues:** |  |  |  |
| Electricity | 380,361 | 337,019 | 300,059 |
| Product | 60,479 | 41,374 | 114,948 |
| Energy storage | 24,495 | 20,353 | 14,060 |
| Total cost of revenues | 465,335 | 398,746 | 429,067 |
| **Gross profit (loss)** |  |  |  |
| Electricity | 251,366 | 248,752 | 241,334 |
| Product | 10,935 | 5,546 | 33,177 |
| Energy storage | 6,523 | 10,040 | 1,764 |
| Total gross profit | 268,824 | 264,338 | 276,275 |
| **Operating expenses:** |  |  |  |
| Research and development expenses | 5,078 | 4,129 | 5,395 |
| Selling and marketing expenses | 16,193 | 15,199 | 17,384 |
| General and administrative expenses | 61,274 | 75,901 | 60,226 |
| Impairment of long-lived assets | 32,648 | — | — |
| Write-off of unsuccessful exploration activities | 828 | — | — |
| Business interruption insurance income | — | (248) | (20,743) |
| Operating income | 152,803 | 169,357 | 214,013 |
| **Other income (expense):** |  |  |  |
| Interest income | 3,417 | 2,124 | 1,717 |
| Interest expense, net | (87,743) | (82,658) | (77,953) |
| Derivatives and foreign currency transaction gains (losses) | (6,044) | (14,720) | 3,802 |
| Income attributable to sale of tax benefits | 33,885 | 29,582 | 25,720 |
| Other non-operating income (expense), net | (709) | (134) | 1,418 |
| Income from operations before income tax and equity in earnings (losses) of investees | 95,609 | 103,551 | 168,717 |
| Income tax (provision) benefit | (14,742) | (24,850) | (67,003) |
| Equity in earnings (losses) of investees, net | (3,072) | (2,624) | 92 |
| Net Income | 77,795 | 76,077 | 101,806 |
| Net income attributable to noncontrolling interest | (11,954) | (13,985) | (16,350) |
| Net income attributable to the Company's stockholders | $65,841 | $62,092 | $85,456 |
| Earnings per share attributable to the Company's stockholders: |  |  |  |
| Basic: | $1.17 | $1.11 | $1.66 |
| Diluted: | $1.17 | $1.10 | $1.65 |
| Weighted average number of shares used in computation of earnings per share attributable to the Company's stockholders: |  |  |  |
| Basic | 56,063 | 56,004 | 51,567 |
| Diluted | 56,503 | 56,402 | 51,937 |

86

### Results as a percentage of revenues

| Revenues: | Year Ended December 31, 2022 | 2021 | 2020 |
| --- | ---: | ---: | ---: |
| Electricity | 86.0% | 88.3% | 76.8% |
| Product | 9.7 | 7.1 | 21.0 |
| Energy storage | 4.2 | 4.6 | 2.2 |
| Total revenues | 100.0 | 100.0 | 100.0 |
| **Cost of revenues:** |  |  |  |
| Electricity | 60.2 | 57.5 | 55.4 |
| Product | 84.7 | 88.2 | 77.6 |
| Energy storage | 79.0 | 67.0 | 88.9 |
| Total cost of revenues | 63.4 | 60.1 | 60.8 |
| **Gross profit (loss)** |  |  |  |
| Electricity | 39.8 | 42.5 | 44.6 |
| Product | 15.3 | 11.8 | 22.4 |
| Energy storage | 21.0 | 33.0 | 11.1 |
| Total gross profit | 36.6 | 39.9 | 39.2 |
| **Operating expenses:** |  |  |  |
| Research and development expenses | 0.7 | 0.6 | 0.8 |
| Selling and marketing expenses | 2.2 | 2.3 | 2.5 |
| General and administrative expenses | 8.3 | 11.4 | 8.5 |
| Impairment charge | 4.4 | 0.0 | 0.0 |
| Write-off of unsuccessful exploration activities | 0.1 | 0.0 | 0.0 |
| Business interruption insurance income | 0.0 | 0.0 | (2.9) |
| Operating income | 20.8 | 25.5 | 30.3 |
| **Other income (expense):** |  |  |  |
| Interest income | 0.5 | 0.3 | 0.2 |
| Interest expense, net | (12.0) | (12.5) | (11.1) |
| Derivatives and foreign currency transaction gains (losses) | (0.8) | (2.2) | 0.5 |
| Income attributable to sale of tax benefits | 4.6 | 4.5 | 3.6 |
| Other non-operating income (expense), net | (0.1) | — | 0.2 |
| Income from continuing operations before income tax and equity in earnings (losses) of investees | 13.0 | 15.6 | 23.9 |
| Income tax (provision) benefit | (2.0) | (3.7) | (9.5) |
| Equity in earnings (losses) of investees, net | (0.4) | (0.4) | — |
| Net Income | 10.6 | 11.5 | 14.4 |
| Net income attributable to noncontrolling interest | (1.6) | (2.1) | (2.3) |
| Net income attributable to the Company's stockholders | 9.0% | 9.4% | 12.1% |

87

### Comparison of the Year Ended December 31, 2022 and the Year Ended December 31, 2021

### Total Revenues

*(Dollars in millions)*

|  | Year Ended December 31, 2022 | Year Ended December 31, 2021 | Increase (Decrease) |  |
| --- | ---: | ---: | ---: | ---: |
| Electricity segment revenues | $631.7 | $585.8 | $46.0 | 7.8% |
| Product segment revenues | 71.4 | 46.9 | 24.5 | 52.2 |
| Energy Storage segment revenues | 31.0 | 30.4 | 0.6 | 2.1 |
| **Total Revenues** | **$734.2** | **$663.1** | **$71.1** | **10.7%** |

For the year ended December 31, 2022, our total revenues increased by 10.7% from $663.1 million in 2021 to $734.2 million in 2022.

#### Electricity Segment

Revenues attributable to our Electricity segment for the year ended December 31, 2022 were $631.7 million, compared to $585.8 million for the year ended December 31, 2021, representing a 7.8% increase. The increase in our Electricity segment revenues was mainly due to (i) higher revenues in Puna of $20.0 million, primarily due to higher electricity rates and the resumption of the power plant to 25MW during the third quarter of 2021; (ii) the full year inclusion of the Dixie Valley and Beowawe power plants following the Terra-Gen acquisition in July 2021, which contributed approximately $21.8 million to the revenues increase; (iii) the start of commercial operation of our CD4 power plant facility in July 2022, which contributed an additional $9.0 million; (iv) the enhancement in McGinness Hills in April 2021, which contributed approximately $4.3 million, and (v) the start of commercial operations of Tungsten Mountain 2 in April 2022, which contributed an additional $4.7 million. This increase was partially offset primarily by a decrease in revenues of approximately $14.6 million as a result of the shutdown at the Heber 1 power plant following a fire that caused damage to the steam turbine in February 2022.

During the years ended December 31, 2022 and 2021, our consolidated power plants generated 6,661,775 MWh and 6,529,140 MWh, respectively, an increase of 2.0%. The average prices during the years ended December 31, 2022 and 2021 were $94.8 and $89.7 per MWh, respectively.

For the year ended December 31, 2022, our Electricity segment generated 86.0% of our total revenues, compared to 88.3% in the previous year, while our Product segment generated 9.7% of our total revenues, compared to 7.1% in the previous year, and our Energy Storage segment generated 4.2% of our total revenues, compared to 4.6% in the previous year.

#### Product Segment

Revenues attributable to our Product segment for the year ended December 31, 2022 were $71.4 million, compared to $46.9 million for the year ended December 31, 2021, representing a 52.2% increase. The increase in our Product segment revenues was due to certain new projects in New Zealand, Nicaragua and Indonesia for which we recorded revenues in 2022 compared to different projects in New Zealand and Chile for which revenues were recorded during 2021.

#### Energy Storage Segment

Revenues attributable to our Energy Storage segment for the year ended December 31, 2022 were $31.0 million compared to $30.4 million for the year ended December 31, 2021, representing a 2.1% increase. The increase was mainly due to higher revenues at PJM and CAISO facilities due to high energy rates and increased performance of the assets in 2022 compared to 2021, primarily offset by a decrease of $6.7 million in revenues from the Rabbit Hill battery energy storage facility primarily as a result of the February 2021 power crisis in Texas, which resulted in a record high increase in demand for electricity on the one hand and a significant decrease in electricity supply in the region on the other hand which led to a significant increase in the Responsive Reserve Service market price during this weather event.

### Total Cost of Revenues

*(Dollars in millions)*

|  | Year Ended December 31, 2022 | Year Ended December 31, 2021 | Increase (Decrease) |  |
| --- | ---: | ---: | ---: | ---: |
| Electricity segment cost of revenues | $380.4 | $337.0 | $43.3 | 12.9% |
| Product segment cost of revenues | 60.5 | 41.4 | 19.1 | 46.2 |
| Energy Storage segment cost of revenues | 24.5 | 20.4 | 4.1 | 20.4 |
| **Total Cost of Revenues** | $465.4 | $398.8 | $66.5 | 16.7% |

#### Electricity Segment

Total cost of revenues attributable to our Electricity segment for the year ended December 31, 2022 was $380.4 million, compared to $337.0 million for the year ended December 31, 2021, representing a 12.9% increase. This increase was primarily attributable to: (i) $20.8 million in higher costs related to the Puna power plant attributable to the resumption of the power plant to 25MW in the third quarter of 2021, including $13.7 million higher business interruption insurance income in 2021, versus 2022; (ii) the full year inclusion of the Dixie Valley and Beowawe power plants following the Terra-Gen acquisition in July 2021, which contributed approximately $20.2 million to the increase in cost of revenues; (iii) the start of commercial operation of our CD4 power plant facility in July 2022, which contributed an additional $4.6 million; and (iv) the start of commercial operations of Tungsten Mountain 2 in April 2022, which contributed an additional $2.5 million. This increase was partially offset by a decrease in cost of revenues of approximately $15.3 million as a result of the shutdown at the Heber 1 power plant following a fire that caused damage to the steam turbine in February 2022. The decrease in cost of revenues related to the Heber 1 fire included $13.8 million of business interruption insurance income recorded in 2022 versus none in 2021.

As a percentage of total Electricity revenues, the total cost of revenues attributable to our Electricity segment for the year ended December 31, 2022 was 60.2%, compared to 57.5% for the year ended December 31, 2021. This increase was primarily attributable to higher operational costs in some of our power plants. The cost of revenues attributable to our international power plants was 18% of our Electricity segment cost of revenues for the year ended December 31, 2022.

#### Product Segment

Total cost of revenues attributable to our Product segment for the year ended December 31, 2022 was $60.5 million, compared to $41.4 million for the year ended December 31, 2021, representing a 46.2% increase from the prior period. This increase was primarily attributable to the increase in Product segment revenues, as discussed above. As a percentage of total Product segment revenues, our total cost of revenues attributable to our Product segment for the year ended December 31, 2022 was 84.7%, compared to 88.2% for the year ended December 31, 2021.

#### Energy Storage Segment

Cost of revenues attributable to our Energy Storage segment for the year ended December 31, 2022 were $24.5 million as compared to $20.4 million in the year ended December 31, 2021. This increase was mainly due to the addition of the Vallecito battery energy storage system to our commercially operating sites in April 2021 and Tierra Buena in June 2022 as well as to the increase in energy storage revenues at our PJM and CAISO facilities as described above.

### Research and Development Expenses

Research and development expenses for the year ended December 31, 2022 were $5.1 million, compared to $4.1 million for the year ended December 31, 2021, represent a 23.0% increase. The increase is mainly attributable to the timing of new development projects that took place during the year ended December 31, 2022 compared to 2021.

### Selling and Marketing Expenses

Selling and marketing expenses for the year ended December 31, 2022 were $16.2 million, compared to $15.2 million for the year ended December 31, 2021, representing a 6.5% increase. The increase was mainly due to an increase in sales commissions as a result of the corresponding increase in Product segment revenues and amortization of stock-based awards. Selling and marketing expenses constituted 2.2% of total revenues for the year ended December 31, 2022, compared to 2.3%, for the year ended December 31, 2021.

### General and Administrative Expenses

General and administrative expenses for the year ended December 31, 2022 were $61.3 million, compared to $75.9 million for the year ended December 31, 2021, representing a 19.3% decrease. The decrease was primarily attributable to: (i) $5.6 million of transaction costs in 2021 including $4.7 million related to the TG Geothermal Portfolio, LLC, acquisition, in July, 2021; (ii) higher legal costs in 2021 mainly associated with the investigation by the Special Committee; (iii) a provision for doubtful debts of $3.0 million included in 2021 related to imbalance charges from the grid operator in respect of our demand response operations that we were unable to collect due to the February 2021 power crisis in Texas; and (iv) a reversal of a contingent liability in 2022 of $1.8 million related to our Guadeloupe power plant acquisition.

General and administrative expenses for the year ended December 31, 2022 constituted 8.3% of total revenues for such period, compared to 11.4%, for the year ended December 31, 2021.

### Impairment of long-lived assets

Impairment of long-lived assets for the year ended December 31, 2022 of $32.6 million is primarily attributable to a non-cash impairment charge related to our Brawley power plant as further described under Note 1 to the consolidated financial statement. There was no such impairment during the year ended December 31, 2021.

### Write-off of Unsuccessful Exploration Activities

Write-offs of unsuccessful exploration activities for year ended December 31, 2022 were $0.8 million compared to none for the year ended December 31, 2021. These write-offs are related to geothermal exploration projects that the Company decided to no longer pursue.

### Interest Expense, Net

Interest expense, net, for the year ended December 31, 2022 was $87.7 million, compared to $82.7 million for the year ended December 31, 2021, representing a 6.2% increase. This increase was primarily due to (i) $5.6 million related to the Convertible Senior Notes which we entered into in June 2022; (ii) $3.3 million of higher interest expenses related to the financing liability assumed as part of the business combination purchase transaction of the Terra-Gen geothermal assets in July 2021; and (iii) $6.6 million of higher interest expenses related to Bank Hapoalim Loan received in July 2021, HSBC Bank Loan received in July 2021, Bank Discount Loan received in September 2021 and Bank Mizrahi Loan received in April 2022. This increase was partially offset by an increase of $4.1 million in interest capitalized to projects under construction, $5.0 million related to the prepayment of Series 3 Bonds in June 2022, and lower interest expenses on other long-term loans as a result of regular principal payments.

### Derivatives and Foreign Currency Transaction Gains (Losses)

Derivatives and foreign currency transaction losses for the year ended December 31, 2022 were $6.0 million, compared to losses of $14.7 million for the year ended December 31, 2021. Derivatives and foreign currency transaction losses for the year ended December 31, 2021 included mainly $14.5 million in losses relating to the hedge transaction associated with our Rabbit Hill battery energy storage facility, due to extreme weather conditions in the area of Georgetown, Texas in February 2021. In addition, derivatives and foreign currency transaction gains and losses includes losses from foreign currency forward contracts which were not accounted for as hedge transactions and which were higher in 2022 than in 2021.

### Income Attributable to Sale of Tax Benefits

Income attributable to the sale of tax benefits for the year ended December 31, 2022 was $33.9 million, compared to $29.6 million for the year ended December 31, 2021. This income primarily represents the value of PTCs and taxable income or loss generated by certain of our power plants allocated to investors under tax equity transactions. The increase of $4.3 million in income attributable to the sale of tax benefits is primarily related to the Steamboat Hills tax monetization transaction which we entered into in October 2021.

### Other Non-Operating Income (Expense), Net

Other non-operating income, net for the year ended December 31, 2022 was $0.7 million, compared to $0.1 million for the year ended December 31, 2021. Other non-operating income for the year ended December 31, 2022 primarily includes a make-whole premium of $1.1 million from the prepayment of Series 3 Bonds during the second quarter of 2022, as further discussed under Note 1 to the consolidated financial statements, net of gain from a sale of certain equipment to a third party.

### Income Taxes

Income tax provision for the year ended December 31, 2022, was $14.7 million, a decrease of $10.1 million compared to an income tax provision of $24.9 million for the year ended December 31, 2021. Our effective tax rate for the year ended December 31, 2022 and 2021, was 15.4% and 24.0%, respectively. The effective rate differs from the federal statutory rate of 21% for the year ended December 31, 2022 due to the jurisdictional mix of earnings at differing tax rates from the federal statutory tax rate, movement in the valuation allowance; and generation of production tax credits.

### Equity in Earnings (losses) of investees, net

Equity in losses of investees, net in the year ended December 31, 2022, was $3.1 million, compared to $2.6 million in the year ended December 31, 2021. Equity in earnings (losses) of investees, net is mainly derived from our 12.75% share in the earnings or losses in Sarulla. During the second quarter of 2022, Sarulla agreed with its banks on a framework that will enable it to perform remediation work that is aimed to improve the plant’s performance. The execution of the phase 1 of the remediation works is underway and major contractors are being mobilized. However, as part of the remediation works involves drilling activities, uncertainty remains regarding Sarulla’s ability to meet the plan and the Company is evaluating periodically the impact of the plan on future performance. As the Company determined that the current situation and circumstances related to its equity investment in Sarulla are temporary, no impairment testing was required at year-end.

***Net Income attributable to the Company’s Stockholders***

Net income attributable to the Company’s stockholders for the year ended December 31, 2022 was $65.8 million, compared to $62.1 million for the year ended December 31, 2021, which represents an increase of $3.7 million. This increase was attributable to the increase of $1.7 million in net income which was affected by the factors described above, as well as a decrease of $2.0 million in net income attributable to noncontrolling interest, mainly attributable to lower allocated income in the year ended December 31, 2022, compared to the year ended December 31, 2021.

### Comparison of the year ended December 31, 2021 and the year ended December 31, 2020

A discussion of changes in our results of operations in 2021 compared to 2020 has been omitted from this Form10-K, but may be found in “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” of our Form 10-K for the fiscal year ended December 31, 2021, filed with the SEC on February 25, 2022, which is incorporated by reference herein. This Form 10-K for the fiscal year ended December 31, 2021 is available free of charge on the SECs website at www.sec.gov and at www.Ormat.com, by clicking “Investors” located at the top of the home page.

### Liquidity and Capital Resources

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

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

As of December 31, 2022, we had access to: (i) $95.9 million in cash and cash equivalents, of which $28.1 million was held by our foreign subsidiaries; and (ii) $390.7 million of unused corporate borrowing capacity under existing lines of credit with different commercial banks.

As of December 31, 2022, $197.4 million in the aggregate was outstanding under credit agreements with several banks as detailed below under “Letters of Credits under the Credit Agreements”.

Our estimated capital needs for 2023 include approximately $589.0 million for capital expenditures on new projects under development or construction including storage projects, exploration activity and maintenance capital expenditures for our existing projects. In addition, we expect $181.7 million for long-term debt repayments.

Our capital expenditures primarily relate to the enhancement of our existing power plants and the construction of new power plants. We have budgeted approximately $570.0 million in capital expenditures for construction of new projects and enhancements to our existing power plants, of which we had invested $245.0 million as of December 31, 2022. We expect to invest approximately $225.0 million in 2023 and the remaining approximately $100.0 million on thereafter.

In addition, we estimate approximately $364.0 million in additional capital expenditures in 2023 to be allocated as follows: (i) approximately $101.0 million for the exploration, drilling and development of new projects and enhancements of existing power plants that are not yet released for full construction; (ii) approximately $60.0 million for maintenance of capital expenditures to our operating power plants; (iii) approximately $183.0 million for the construction and development of storage projects; and (iv) approximately $20.0 million for enhancements to our production facilities.

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

### Letters of Credits under the Credit Agreements

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

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

*(Dollars in millions)*

| Credit Agreements | Amount Issued | Issued and Outstanding as of December 31, 2022 | Termination Date |
| --- | ---: | ---: | --- |
| Committed lines for credit and letters of credit | $468.0 | $77.3 | March 2023 - Jul 2025 |
| Committed lines for letters of credit | 155.0 | 105.2 | April 2023 - December 2023 |
| Non-committed lines | - | 14.9 | October 2023 |
| **Total** | **$623.0** | **$197.4** |  |

### Restrictive covenants

Our obligations under the credit agreements, the loan agreements, and the trust instrument governing the bonds described above, are unsecured, but we are subject to a negative pledge in favor of the banks and the other lenders and certain other restrictive covenants. These include, among other things, a prohibition on: (i) creating any floating charge or any permanent pledge, charge or lien over our assets without obtaining the prior written approval of the lender; (ii) guaranteeing the liabilities of any third party without obtaining the prior written approval of the lender; and (iii) selling, assigning, transferring, conveying or disposing of all or substantially all of our assets, or a change of control in our ownership structure. Some of the credit agreements, the term loan agreements, and the trust instrument contain cross-default provisions with respect to other material indebtedness owed by us to any third party. In some cases, we have agreed to maintain certain financial ratios, which are measured quarterly, such as: (i) equity of at least $750 million and in no event less than 25% of total assets; and (ii) 12-month debt, net of cash, cash equivalents, and short-term bank deposits to Adjusted EBITDA ratio not to exceed 6. As of December 31, 2022: (i) total equity was $2,021.0 million and the actual equity to total assets ratio was 43.8%; and (ii) the 12-month debt, net of cash and cash equivalents to Adjusted EBITDA ratio was 4.13. During the year ended December 31, 2022, we distributed interim dividends in an aggregate amount of $27.1 million. The failure to perform or observe any of the covenants set forth in such agreements, subject to various cure periods, would result in the occurrence of an event of default and would enable the lenders to accelerate all amounts due under each such agreement.

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

As of December 31, 2022, we did not meet the covenants related to the DAC 1 Senior Secured Notes which resulted in certain equity distribution restrictions from the related subsidiary.

### Credit Agreements

### Credit Agreement with MUFG Union Bank

Ormat Nevada has a credit agreement with MUFG Union Bank under which it has an aggregate available credit of up to $60.0 million as of December 31, 2022.The credit termination date is June 30, 2023.

The facility is limited to the issuance, extension, modification or amendment of letters of credit. Union Bank is currently the sole lender and issuing bank under the credit agreement, but is also designated as an administrative agent on behalf of banks that may, from time to time in the future, join the credit agreement as lenders. In connection with this transaction, the Company entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which the Company agreed to guarantee Ormat Nevada’s obligations under the credit agreement. Ormat Nevada’s obligations under the credit agreement are otherwise unsecured. There are various restrictive covenants under the credit agreement, which include a requirement to comply with the following financial ratios, which are measured quarterly: (i) a 12-month debt to EBITDA ratio not to exceed 4.5; (ii) 12-month DSCR of not less than 1.35; and (iii) distribution leverage ratio not to exceed 2.0. As of December 31,2022: (i) the actual 12-month debt to EBITDA ratio was 2.04; (ii) the 12-month DSCR was 3.91; and (iii) the distribution leverage ratio was 0.63. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios, and subject to specified carve-outs and exceptions, a negative pledge on the assets of Ormat Nevada in favor of Union Bank. As of December 31, 2022, the covenants have been met. As of December 31, 2022, letters of credit in the aggregate amount of $57.6 million were issued and outstanding under this credit agreement.

### Credit Agreement with HSBC Bank USA N.A.

Ormat Nevada has a credit agreement with HSBC Bank USA, N.A for one year with annual renewals. The current expiration date of the facility under this credit agreement is October 31, 2023. On December 31, 2022, the aggregate amount available under the credit agreement was $35.0 million. This credit line is limited to the issuance, extension, modification or amendment of letters of credit. In addition, Ormat Nevada has an uncommitted discretionary demand line of credit in the aggregate amount of $35.0 million available for letters of credit including up to $20 million of credit. In connection with this transaction, the Company entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which the Company agreed to guarantee Ormat Nevada’s obligations under the credit agreement. Ormat Nevada’s obligations under the credit agreement are otherwise unsecured.

There are various restrictive covenants under the credit agreement, including a requirement to comply with the following financial ratios, which are measured quarterly: (i) a 12-month debt to EBITDA ratio not to exceed 4.5; (ii) 12-month DSCR of not less than 1.35; and (iii) distribution leverage ratio not to exceed 2.0. As of December 31, 2022: (i) the actual 12-month debt to EBITDA ratio was 2.04; (ii) the 12-month DSCR was 3.91; and (iii) the distribution leverage ratio was 0.63. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios, and subject to specified carve-outs and exceptions, a negative pledge on the assets of Ormat Nevada in favor of HSBC. As of December 31, 2022, the covenants have been met.

As of December 31, 2022, letters of credit in the aggregate amount of $34.2 million were issued and outstanding under the committed portion of this credit agreement and $4.8 million under the uncommitted portion of the agreement.

### Future minimum payments

Future minimum payments under long-term obligations as of December 31, 2022, are detailed under the caption Contractual Obligations and Commercial Commitments, below.

### Third-Party Debt

Our third-party debt consists of (i) non-recourse and limited-recourse project finance debt or acquisition financing that we or our subsidiaries have obtained for the purpose of developing and constructing, refinancing or acquiring our various projects; (ii) full-recourse debt incurred by us or our subsidiaries for general corporate purposes; (iii) convertible senior note issued in June 2022 as further described under Note 1 to the consolidated financial statements; and (iv) financing liability assumed as part of the TG Geothermal Portfolio, LLC acquisition as further described under note 2 to the consolidated financial statements.

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

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

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

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

*(Dollars in millions)*

| Loan | Line of Credit | Amount Outstanding as of December 31, 2022 | Interest Rate | Maturity Date | Related Projects | Location |
| --- | ---: | ---: | ---: | --- | --- | --- |
| OFC 2 Senior Secured Notes – Series A | $151.7 | $71.8 | 4.69% | 2032 | McGinness Hills phase 1 and Tuscarora | United States |
| OFC 2 Senior Secured Notes – Series B | 140.0 | 86.3 | 4.61% | 2032 | McGinness Hills phase 2 | United States |
| Olkaria III Financing Agreement with DFC – Tranche 1 | 85.0 | 37.8 | 6.34% | 2030 | Olkaria III Complex | Kenya |
| Olkaria III Financing Agreement with DFC – Tranche 2 | 180.0 | 79.4 | 6.29% | 2030 | Olkaria III Complex | Kenya |
| Olkaria III Financing Agreement with DFC – Tranche 3 | 45.0 | 21.5 | 6.12% | 2030 | Olkaria III Complex | Kenya |
| Amatitlan Financing (1) | 42.0 | 15.8 | LIBOR+4.35% | 2027 | Amatitlan | Guatemala |
| Don A. Campbell Senior Secured Notes | 92.5 | 62.7 | 4.03% | 2033 | Don A. Campbell Complex | United States |
| Idaho Refinancing Note (2) | 61.6 | 61.6 | 6.26% | 2038 | Neal Hot Springs and Raft River | United States |
| U.S. Department of Energy loan (3) | 96.8 | 32.8 | 2.61% | 2035 | Neal Hot Springs | United States |
| Prudential Capital Group Nevada Loan | 30.7 | 25.0 | 6.75% | 2037 | San Emidio | United States |
| Platanares Loan with DFC | 114.7 | 79.9 | 7.02% | 2032 | Platanares | Honduras |
| Viridity - Plumstriker | 23.5 | 11.4 | LIBOR+3.5% | 2026 | Plumsted Striker | United States |
| Geothermie Bouillante (4) | 8.9 | 4.6 | 1.52% | 2026 | Geothermie Bouillante | Guadeloupe |
| Geothermie Bouillante (4) | 8.9 | 5.8 | 1.93% | 2026 | Geothermie Bouillante | Guadeloupe |
| **Total** | **$1,081.3** | **$596.4** |  |  |  |  |

(1) LIBOR Rate cannot be lower than 1.25%. Margin of 4.35% as long as the Company’s guaranty of the loan is outstanding (current situation) or 4.75% otherwise. As of December 31, 2022, interest rate is 5.6%.

(2) Secured by equity interest.

(3) Secured by the assets.

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

### Full-Recourse Third-Party Debt

*(Dollars in millions)*

| Loan | Amount Issued | Amount Outstanding as of December 31, 2022 | Interest Rate | Maturity Date |
| --- | ---: | ---: | ---: | --- |
| Mizrahi Loan | $75.0 | $70.3 | 4.10% | April 2030 |
| Hapoalim Loan | 125.0 | 98.2 | 3.45% | June 2028 |
| HSBC Loan | 50.0 | 42.9 | 3.45% | July 2028 |
| Discount Loan | 100.0 | 87.5 | 2.90% | September 2029 |
| Senior Unsecured Bonds Series 4 (1) | 289.8 | 255.8 | 3.35% | June 2031 |
| Senior Unsecured Loan 1 | 100.0 | 87.4 | 4.80% | March 2029 |
| Senior Unsecured Loan 2 | 50.0 | 43.7 | 4.60% | March 2029 |
| Senior Unsecured Loan 3 | 50.0 | 43.7 | 5.44% | March 2029 |
| DEG Loan 2 | 50.0 | 27.5 | 6.28% | June 2028 |
| DEG Loan 3 | 41.5 | 24.0 | 6.04% | June 2028 |
| **Total** | **$1,149.3** | **$781.0** |  |  |

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

### Financing Liability

*(Dollar in millions)*

| Loan | Amount Outstanding as of December 31, 2022 | Annual Interest Rate | Maturity Date (1) |
| --- | ---: | ---: | --- |
| Financing Liability - Dixie Valley | $242.0 | 2.55% | March 2033 |

(1) final maturity date of the financing liability is assuming execution of the buy-out option in September 2024.

### Convertible Senior Notes

*(Dollar in millions)*

| Loan | Amount Outstanding as of December 31, 2022 | Annual Interest Rate | Maturity Date (1) |
| --- | ---: | ---: | --- |
| Convertible Senior Notes | $431.3 | 2.50% | July 2027 |

(1) The Notes mature In July 2027, unless earlier converted, redeemed or repurchased.

For additional description of our long term debt, see Note 12, Long-term Debt, Credit Agreements and Financial Liability to our consolidated financial statements, set forth in Item 8 of this Annual Report.

### Liquidity Impact of Uncertain Tax Positions

As discussed in Note 17 - Income Taxes, to our consolidated financial statements set forth in Item 8 of this Annual Report, we have a liability associated with unrecognized tax benefits and related interest and penalties in the amount of approximately $6.6 million as of December 31, 2022. This liability is included in long-term liabilities in our consolidated balance sheet, because we generally do not anticipate that settlement of the liability will require payment of cash within the next 12 months. We are not able to reasonably estimate when we will make any cash payments required to settle this liability.

### Dividends

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

The following are the dividends declared by us during the past two years, as of December 31, 2022:

| Date Declared | Dividend Amount per Share | Record Date | Payment Date |
| --- | ---: | --- | --- |
| February 24, 2021 | $0.12 | March 11, 2021 | March 29, 2021 |
| May 5, 2021 | $0.12 | May 18, 2021 | June 1, 2021 |
| August 4, 2021 | $0.12 | August 18, 2021 | September 1, 2021 |
| November 3, 2021 | $0.12 | November 17, 2021 | December 3, 2021 |
| February 23, 2022 | $0.12 | March 9, 2022 | March 23, 2022 |
| May 2, 2022 | $0.12 | May 16, 2022 | May 31, 2022 |
| August 3, 2022 | $0.12 | August 17, 2022 | August 31, 2022 |
| November 2, 2022 | $0.12 | November 16, 2022 | November 30, 2022 |
| February 22, 2023 | $0.12 | March 8, 2023 | March 22, 2023 |

### Historical Cash Flows

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

*(Dollars in thousands)*

|  | Year Ended December 31, 2022 | 2021 | 2020 |
| --- | ---: | ---: | ---: |
| Net cash provided by operating activities | $280,974 | $258,822 | $265,005 |
| Net cash used in investing activities | (523,406) | (638,193) | (385,969) |
| Net cash provided by (used in) financing activities | 126,273 | 186,385 | 503,478 |
| Translation adjustments on cash and cash equivalents | (609) | (348) | 1,154 |
| Net change in cash and cash equivalents and restricted cash and cash equivalents | $(116,768) | $(193,334) | $383,668 |

#### For the Year Ended December 31, 2022

Net cash provided by operating activities for the year ended December 31, 2022 was $281.0 million, compared to $258.8 million for the year ended December 31, 2021. The net increase of $22.2 million resulted primarily from (i) an increase in net income of $1.7 million in 2022 compared to 2021, adjusted by an increase in depreciation an amortization of $15.8 million in 2022 compared to 2021, and an increase in impairment of long-lived assets of $32.6 million in 2022 compared to 2021. Additional contributors to the increase in net cash provided by operating activities were an increase in the change in accounts payable and accrued expenses of $19.9 million, mainly due to timing of payments to our supplier and a decrease in the change in prepaid expenses and other of $24.0 million in 2022 compared to 2021. This increase was partially offset by: (i) an increase in the change in receivables of $46.7 million in 2022 compared to 2021, due to timing of collections from our customers; (ii) a decrease in the change of costs and estimated earnings in excess of billing on uncompleted contracts, net of $21.6 million in 2022 compared to 2021, as a result of timing of billing to our customers.

Net cash used in investing activities for the year ended December 31, 2022 was $523.4 million, compared to $638.2 million for the year ended December 31, 2021. The principal factors that affected the decrease in our net cash used in investing activities during the year ended December 31, 2022 were: (i) cash provided from the purchase, maturities and sale and of marketable securities of $42.8 million in 2022 compared to cash used for purchase of marketable securities, net maturities of $43.8 million in 2021; and (ii) cash paid for the purchase transaction of Terra-Gen for a total consideration of $171.0 million in 2021, compared to none in 2022. This increase was partially offset by capital expenditures of $563.5 million in 2022 compared to $419.3 million in the prior year, primarily for our facilities under construction that support our growth plan.

Net cash provided by financing activities for the year ended December 31, 2022 was $126.3 million, compared to $186.4 million provided by financing activities for the year ended December 31, 2021. The principal factors that affected the decrease in net cash provided by financing activities were: (i) $135.3 million proceeds from long-term loans from banks in 2022 compared to $275.0 million during 2021; (ii) $219.1 million of prepayment of Series 3 Bond and $185.2 million of long-term loans compared to $93.0 million in 2021; (iii) purchase of capped call instruments of $24.5 million in 2022, and purchase of treasury stock of $18.0 million in 2022, partially offset by proceeds from issuance of convertible notes, net of $419.7 million in 2022.

#### For the Year Ended December 31, 2021

A discussion of changes in our cash flows in 2021 compared to 2020 has been omitted from this Form10-K, but may be found in “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” of our Form 10-K for the fiscal year ended December 31, 2021, filed with the SEC on February 25, 2022, which is incorporated by reference herein. This Form 10-K is available free of charge on the SECs website at www.sec.gov and at www.Ormat.com, by clicking “Investors” located at the top of the home page.

### Total EBITDA and Adjusted EBITDA

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

Starting in the fourth quarter of 2022, we include accretion expenses related to asset retirement obligation in the adjustments to net income when calculating EBITDA and adjusted EBITDA. The presentation of EBITDA and adjusted EBITDA includes accretion expenses for the fiscal year ended December 31, 2022, however, the prior years have not been recast to include accretion expenses as the amounts were immaterial.

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

Net income for the year ended December 31, 2022 was $77.8 million, compared to $76.1 million for the year ended December 31, 2021 and $101.8 million for the year ended December 31, 2020.

Adjusted EBITDA for the year ended December 31, 2022 was $435.5 million, compared to $401.4 million for the year ended December 31, 2021 and $420.2 million for the year ended December 31, 2020.

The following table reconciles net income to EBITDA and Adjusted EBITDA for the years ended December 31, 2022, 2021 and 2020:

*(Dollars in thousands)*

|  | Year Ended December 31, 2022 | 2021 | 2020 |
| --- | ---: | ---: | ---: |
| Net income | $77,795 | $76,077 | $101,806 |
| Adjusted for: |  |  |  |
| Interest expense, net (including amortization of deferred financing costs) | 84,326 | 80,534 | 76,236 |
| Income tax provision (benefit) | 14,742 | 24,850 | 67,003 |
| Adjustment to investment in an unconsolidated company: our proportionate share in interest expense, tax and depreciation and amortization in Sarulla complex | 13,199 | 14,680 | 11,549 |
| Depreciation, amortization and accretion | 198,603 | 177,930 | 151,371 |
| **EBITDA** | **388,665** | **374,071** | **407,965** |
| Mark-to-market on derivative instruments | 1,613 | 741 | (1,192) |
| Stock-based compensation | 11,646 | 9,168 | 9,830 |
| Make-whole premium related to long-term debt prepayment | 1,102 | — | — |
| Reversal of a contingent liability related to a business combination | (1,829) | (418) | — |
| Allowance for bad debts related to February power crisis in Texas | 115 | 2,980 | — |
| Hedge losses resulting from February power crisis in Texas | — | 9,133 | — |
| Impairment of long-lived assets | 32,648 | — | — |
| Write-off of unsuccessful exploration activities | 828 | — | — |
| Merger and acquisition transaction costs | 675 | 5,635 | 2,279 |
| Legal settlement expenses | — | — | 1,277 |
| Tender-related deposits write-off | — | 134 | — |
| **Adjusted EBITDA** | **$435,463** | **$401,444** | **$420,159** |

98

Adjusted EBITDA for fiscal year 2022 increased by 8.5% compared to fiscal year 2021, primarily due to an increase in gross profit of our Electricity and Product segments together with a decrease in general and administrative expenses, partially offset by a decrease in the Energy Storage segment gross profit.

EBITDA and Adjusted EBITDA include our proportionate share (12.75%) of Sarulla's EBITDA and Adjusted EBITDA, respectively.

On May 2014, the Sarulla consortium (“SOL”) closed $1,170 million in financing. As of December 31, 2022, the credit facility has an outstanding balance of $876.2 million. Our proportionate share in the SOL credit facility is $111.7 million. In September 2022, the last calculation period, Sarulla was able to meet its historical debt service coverage ratio (“DSCR”) covenant under the credit facility agreement notwithstanding the lower performance of the power plants, and it was able to pay the entire current Extended Political Risk Guaranty (“EPRG”) premium due in September 2022 (but not to eliminate the overdue EPRG amount of approx. $1.5 million from past periods). For the calculation period ending on March 2023, the consortium projects that it will be able to meet the historical DSCR covenant and to eliminate overdue EPRG premiums, however, for the next calculation period between March – September 2023 the consortium projects that the minimum DSCR requirement and the payment obligation of the EPRG premium will not be met. During the second quarter of 2022, Sarulla agreed with its banks on a framework that will enable it to perform remediation work that is aimed to improve the plant’s performance. The execution of the phase 1 of the remediation works is underway and major contractors are being mobilized. However, as part of the remediation works involves drilling activities, uncertainty remains regarding Sarulla’s ability to meet the plan and the Company is evaluating periodically the impact of the plan on future performance. As the Company determined that the current situation and circumstances related to its equity investment in Sarulla are temporary, no impairment testing was required at year-end. As of December 31, 2022, the carrying value of our equity investment in SOL is $74.9 million.

### Exposure to Market Risks

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

The energy payments under the PPAs of the Heber 2 power plant in the Heber Complex until the end of 2022, are determined by reference to the relevant power purchaser’s short run avoided cost. A decline in the price of natural gas will result in a decrease in the incremental cost that the power purchaser avoids by not generating its electrical energy needs from natural gas, or by reducing the price of purchasing its electrical energy needs from natural gas power plants, which in turn will reduce the energy payments that we may charge under the relevant PPA for these power plants. The Puna Complex is currently benefiting from energy prices which are higher than the floor under the 25 MW PPA for the Puna Complex. For Heber 2 power plant we signed a new PPA and for Puna we are currently negotiating a new PPA, for both with a fixed energy rate, as discussed above.

As of December 31, 2022, 98.7% of our consolidated long-term debt was fixed rate debt and therefore was not subject to interest rate volatility risk and 1.3% of our long-term debt was floating rate debt, exposing us to interest rate risk in connection therewith. As of December 31, 2022, $27.1 million of our long-term debt remained subject to interest rate risk.

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

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

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

We performed a sensitivity analysis on the fair values of our long-term debt obligations, and foreign currency exchange forward contracts. The foreign currency exchange forward contracts listed below principally relate to trading activities. The sensitivity analysis involved increasing and decreasing forward rates at December 31, 2022 and 2021 by a hypothetical 10% and calculating the resulting change in the fair values.

At this time, the development of our strategic plan has not exposed us to any additional market risk. However, as the implementation of the plan progresses, we may be exposed to additional or different market risks.

The results of the sensitivity analysis calculations as of December 31, 2022 and 2021 are presented below:

*(In thousands)*

| Risk | Assuming a 10% Increase in Rates As of December 31, 2022 | 2021 | Assuming a 10% Decrease in Rates As of December 31, 2022 | 2021 | Change in the Fair Value of |
| --- | ---: | ---: | ---: | ---: | --- |
| **Foreign Currency** | $(5,093) | $(2,719) | $6,220 | $3,324 | Foreign Currency Forward Contracts |
| **Interest Rate** | $(1,493) | $(1,131) | $1,531 | $1,148 | Hapoalim Loan |
| **Interest Rate** | $(631) | $(557) | $648 | $566 | HSBC Loan |
| **Interest Rate** | $(1,378) | $(1,119) | $1,416 | $1,131 | Discount Loan |
| **Interest Rate** | $(4,096) | $(3,394) | $4,232 | $3,465 | Financing Liability |
| **Interest Rate** | $(3,693) | $(3,069) | $3,832 | $3,146 | OFC 2 Senior Secured Notes |
| **Interest Rate** | $(3,178) | $(2,946) | $3,295 | $3,025 | DFC Loan |
| **Interest Rate** | $(259) | $(226) | $268 | $231 | Amatitlan Loan |
| **Interest Rate** | $(5,701) | $(3,833) | $5,925 | $3,880 | Senior Unsecured Bonds |
| **Interest Rate** | $(527) | $(494) | $544 | $505 | DEG 2 Loan |
| **Interest Rate** | $(1,528) | $(1,286) | $1,597 | $1,324 | DAC 1 Senior Secured Notes |
| **Interest Rate** | $(3,902) | $(3,135) | $4,045 | $3,214 | Migdal Loan and the Additional Migdal Loan and the Second Addendum Migdal Loan |
| **Interest Rate** | $(986) | $(920) | $1,051 | $965 | San Emidio Loan |
| **Interest Rate** | $(748) | $(539) | $775 | $550 | DOE Loan |
| **Interest Rate** | $(2,430) | $(88) | $2,606 | $89 | Idaho Holdings Loan |
| **Interest Rate** | $(2,198) | $(2,035) | $2,293 | $2,100 | Platanares DFC Loan |
| **Interest Rate** | $(435) | $(389) | $448 | $397 | DEG 3 Loan |
| **Interest Rate** | $(155) | $(121) | $158 | $123 | Plumstriker Loan |
| **Interest Rate** | $(96) | $(81) | $97 | $82 | Other long-term loans |

100

In July 2019, the United Kingdom’s Financial Conduct Authority (the “FCA”), which regulates LIBOR (London Interbank Offered Rate), announced that it intends to phase out LIBOR. LIBOR is still in use and being published until its phaseout in June 2023 in order to allow a transition period mainly for contracts that already exist using LIBOR. Additionally, the FCA has stated that no new contracts using U.S. dollar LIBOR should be entered into after December 31, 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, a steering committee comprised of large U.S. financial institutions, is considering replacing U.S. dollar LIBOR with a new index calculated by short-term repurchase agreements, backed by Treasury securities ("SOFR"). SOFR is observed and backward-looking, which stands in contrast with LIBOR under the current methodology, which is an estimated forward-looking rate and relies, to some degree, on the expert judgment of submitting panel members. Given that SOFR is a secured rate backed by government securities, it would not take into account bank credit risk (as is the case with LIBOR). Therefore, the SOFR rate, if adopted, would likely be lower than LIBOR rates and is less likely to correlate with the funding costs of financial institutions.

We have evaluated the impact of the transition from LIBOR, and currently believe that the transition will not have a material impact on our consolidated financial statements.

### Effect of Inflation

We are seeing an increase in overall operating and other costs as the result of higher inflation rates, in particular in the United States. In addition, we are experiencing an increase in raw material cost and supply chain delays, which may put pressure on our operating margins in the Product segment and increases our cost to build our own power plants and energy storage assets. To address the possibility of rising inflation, some of our contracts include certain provisions that mitigate inflation risk.

In connection with the Electricity segment, none of our U.S. PPAs, including the SCPPA Portfolio PPA, are directly linked to the Consumer Price Index ("CPI"). Inflation may directly impact an expense we incur for the operation of our projects, thereby increasing our overall operating costs and reducing our profit and gross margin. The negative impact of inflation would be partially offset by price adjustments built into some of our PPAs that could be triggered upon such occurrences. In addition to the Heber 2 and part of the Puna rates that are impacted by higher commodity prices, the energy payments pursuant to our PPAs for some of our power plants such as the Brady power plant, the Steamboat 2 and 3 power plants and the McGinness Complex increase every year through the end of the relevant terms of such agreements, although such increases are not directly linked to the CPI or any other inflationary index. Lease payments are generally fixed, while royalty payments are generally calculated as a percentage of revenues and therefore are not significantly impacted by inflation. In our Product segment, inflation may directly impact fixed and variable costs incurred in the construction of third party power plants, thereby lowering our profit margins at the Product segment. We are more likely to be able to offset long term, all or part of this inflationary impact through our project pricing. With respect to power plants that we build for our own electricity production, inflationary pricing may impact our operating costs which may be partially offset in the pricing of the new long-term PPAs that we negotiate.

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

### Contractual Obligations and Commercial Commitments

The following tables set forth our material contractual obligations as of December 31, 2022 (in thousands):

|  | Payments Due by Period Remaining Total | 2023 | 2024 | 2025 | 2026 | 2027 | Thereafter |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Long-term debt and financing liabilities - principal | $2,052,601 | $181,660 | $261,622 | $176,309 | $177,539 | $605,013 | $650,458 |
| Interest on long-term debt and financing liabilities (1) | 290,912 | 69,658 | 52,854 | 43,558 | 36,496 | 29,968 | 58,377 |
| Finance lease obligations | 4,119 | 1,710 | 1,031 | 866 | 483 | 29 | — |
| Operating lease obligations | 34,366 | 2,925 | 2,547 | 2,225 | 2,086 | 1,897 | 22,686 |
| Benefits upon retirement (2) | 12,147 | 2,156 | 81 | 508 | 406 | 529 | 8,467 |
| Asset retirement obligation | 97,660 | — | — | — | — | — | 97,660 |
| Purchase commitments (3) | 569,881 | 569,881 | — | — | — | — | — |
|  | $3,061,686 | $827,990 | $318,135 | $223,466 | $217,010 | $637,436 | $837,648 |

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

(2) The above amounts were determined based on employees’ current salary rates and the number of years’ service that will have been accumulated at their expected retirement date. These amounts do not include amounts that might be paid to employees that will cease working with us before reaching their expected retirement age.

(3) We purchase raw materials for inventories, construction-in-process and services from a variety of vendors. During the normal course of business, in order to manage manufacturing lead times and help assure adequate supply, we enter into agreements with contract manufacturers and suppliers that either allow them to procure goods and services based upon specifications defined by us, or that establish parameters defining our requirements. At December 31, 2022, total obligations related to such supplier agreements were approximately $569.9 million (approximately $404.1 million of which relate to construction-in-process). All such obligations are payable in 2023.

The table above does not reflect unrecognized tax benefits of $6.6 million, the timing of which is uncertain. Refer to Note 17 to our consolidated financial statements set forth in Item 8 of this Annual Report for additional discussion of unrecognized tax benefits. The above table also does not reflect a liability associated with the sale of tax benefits of $166.3 million, the timing of which is uncertain and other long-term liabilities of $3.3 million that are deemed immaterial. Refer to Note 13 to our consolidated financial statements as set forth in Item 8 of this Annual Report for additional discussion of our liability associated with the sale of tax benefits.

### Concentration of Credit Risk

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

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

|  | Year Ended December 31, 2022 | 2021 | 2020 |
| --- | ---: | ---: | ---: |
| Southern California Public Power Authority (“SCPPA”) | 21.5% | 23.7% | 20.6% |
| Sierra Pacific Power Company and Nevada Power Company | 16.9 | 18.6 | 17.5 |
| Kenya Power and Lighting Co. Ltd. ("KPLC") | 14.4 | 15.5 | 16.4 |

We have historically been able to collect on substantially all of our receivable balances. As of December 31, 2022, the amount overdue from KPLC in Kenya was $27.0 million of which $15.2 million was paid in January and February of 2023 The Company believes it will be able to collect all past due amounts in Kenya. This belief is supported by the fact that in addition to KPLC's obligations under its power purchase agreement, the Company holds a support letter from the Government of Kenya that covers certain cases of KPLC non-payment (such as where caused by government actions and/or political events).

In Honduras, as of December 31, 2022, the total amount overdue from ENEE was $13.9 million of which $2.6 million was collected in February 2023. In addition, due to continuing restrictive measures related to the COVID-19 pandemic in Honduras, the Company may experience additional delays in collection. The Company believes it will be able to collect all past due amounts in Honduras.

### Government Grants and Tax Benefits

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

We are also permitted to depreciate most of the cost of a new geothermal power plant. In cases where we claim ITC, our tax basis in the plant that is eligible for depreciation is reduced by one-half of the ITC amount. In cases where we claim the PTC, there is no reduction in the tax basis for depreciation. Following the IRA, projects that were or will be placed in service after September 27, 2017, could qualify for a 100% bonus depreciation with respect to its qualifying assets. After applying any depreciation bonus that is available, we can depreciate the remainder of our tax basis in the plant, if any, mostly over five years on an accelerated basis, meaning that more of the cost may be deducted in the first few years than during the remainder of the depreciation period. We will continue to analyze this new provision under the IRA and determine if an election is appropriate as it relates to our business needs.

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

## Market risk

As filed, 168 characters.

Information responding to Item 7A is included in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report.

## Controls and procedures

As filed, 2,902 characters.

### Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO (principal executive officer) and CFO (principal financial officer), as appropriate, to allow for timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

As required by SEC Rule 13a-15(e), we carried out an evaluation, under the supervision and with the participation of our management, including our CEO and CFO, of the effectiveness of our disclosure controls and procedures as of December 31, 2022. Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2022 to provide the reasonable assurance described above.

### Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

**Management’s Report on Internal Control over Financial Reporting**

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) of the Exchange Act. Under the supervision and with the participation of our management, including the CEO and the CFO, we carried out an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2022 using the criteria established in “Internal Control-Integrated Framework” (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on that evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2022.

Our internal control over financial reporting as of December 31, 2022 has been audited by Kesselman & Kesselman, Certified Public Accountants (Isr.), an independent registered public accounting firm and a member of PricewaterhouseCoopers International Limited (“PwC”), as stated in their report which is included under “Item 8—Financial Statements.”

Filed Feb 24, 2023.
Source: SEC EDGAR, the filing index for accession 0001437749-23-004477. Last ingested by Listed: Nov 4, 2026, 18:33 ET. No prices; not investment advice.