ORMAT TECHNOLOGIES, INC. (ORA) FY 2021 MD&A

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

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

General

Overview of Fiscal Year 2021 Revenues

Recent Developments

The most significant recent developments for our company and business during 2021 and 2020 to date are described below.

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COVID-19 Update

The Company has implemented significant measures and continues to make efforts in order to meet government requirements and preserve the health and safety of its employees. The Company’s preventative measures against COVID-19, including, most recently, the spread of variant strains, including working remotely when needed and adopting separate shifts in its power plants, manufacturing facilities and other locations while working to continue operations at close to full capacity in all locations. Since the end of the second quarter of 2021, the Company has experienced an easing of government restrictions in a number of countries, including Israel, but uncertainty around the impact of COVID-19 continues. With respect to its employees, the Company has not laid-off or furloughed any employees due to COVID-19 and has continued to pay full salaries. We will continue to monitor developments affecting both our workforce and our customers, and we have taken, and will continue to take, health and safety measures that we determine are necessary in order to mitigate the impacts. To date, as a result of these business continuity measures, the Company has not experienced material disruptions in our operations due to COVID-19, but has nevertheless experienced the following impacts on our segment operations:

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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”:

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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 93.5% of our Electricity revenues for the year ended December 31, 2021 were derived from PPAs with fixed price components, we have variable price PPAs in California and 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, as follows:

Accordingly, our revenues from those power plants 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. Some of our PPAs provide for bonus payments in the event that we are able to exceed certain capacity target levels and the potential forfeiture of payments if we fail to meet certain minimum capacity target levels. Energy payments, on the other hand, 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 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 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:

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Geographic Breakdown of Results of Operations

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

In 2021, 2020 and 2019, 34%, 49% 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 69%, 63% and 62% of our total Electricity segment for the years ended December 31, 2021, 2020 and 2019, 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 2021 and 2020 the international operations of the segment accounted for 45% and 51% of our total gross profits, 68% and 70% of our net income (assuming the majority of corporate operating expenses and financing are recorded under domestic jurisdiction) and 42% and 45% of our EBITDA, respectively.

Product Segment. Our Product segment foreign revenues were 88%,  96% and 84% of our total Product segment revenues for the years ended December 31, 2021, 2020 and 2019, 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, 2021, 2020 and 2019, 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 one of the Heber 2 power plant in the Heber Complex, 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.

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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 4.3% and 3.8% of Electricity segment revenues for the years ended December 31, 2021 and 2020, 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:

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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 $50.7 million and $51.5 million at December 31, 2021 and 2020, respectively.

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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, 2021, 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.

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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 partial 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.

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Results of Operations

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

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Results as a percentage of revenues

Comparison of the Year Ended December 31, 2021 and the Year Ended December 31, 2020

Total Revenues

For the year ended December 31, 2021, our total revenues decreased by (6.0)% (from $705.3 million to $663.1 million) over the previous year driven by lower revenues in the Product segment.

Electricity Segment

Revenues attributable to our Electricity segment for the year ended December 31, 2021 were $585.8 million, compared to $541.4 million for the year ended December 31, 2020, representing a 8.2% increase. The increase in our Electricity segment revenues was mainly due to (i) the consolidation of the Dixie Valley and Beowawe power plants following the Terra-Gen acquisition in July 2021, with revenues of $23.2 million and $3.0 million, respectively; (ii) the enhancement of the Steamboat Hills power plant in June 2020; (iii) the resumption of operations of the Puna power plant to 25MW in the third quarter of 2021; and (iv) the expansion of the McGinness Hills complex in May 2021, partially offset by a decrease in revenues from the Olkaria complex  due to lower resource performance that caused a capacity reduction, from Bouillante power plant due to temporary limitations in our ability to utilize the resource.

During the years ended December 31, 2021 and 2020, our consolidated power plants generated 6,529,140 MWh and 6,043,993 MWh, respectively, an increase of 8.0%. The average prices during the years ended December 31, 2021 and 2020 were $89.7 and $89.6 per MWh, respectively.

For the year ended December 31, 2021, our Electricity segment generated88.3% of our total revenues, compared to 76.8% in the previous year, while our Product segment generated 7.1% of our total revenues, compared to 21.0% in the previous year, and our Energy Storage segment generated 4.6% of our total revenues, compared to 2.2% in the previous year.

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Product Segment

Revenues attributable to our Product segment for the year ended December 31, 2021 were $46.9 million, compared to $148.1 million for the year ended December 31, 2020, representing a 68.3% decrease. The decrease in our Product segment revenues was mainly due to a slowdown in product sales as a result of COVID-19, projects in Turkey, New Zealand and Chile, which started in 2019, and provided $98.3 million in revenue recognized during the year ended December 31, 2020, compared to $10.1 million in the year ended December 31, 2021, and projects in Turkey, which started in 2020, and provided $23.6 million in revenue recognized during the year ended December 31, 2020, compared to zero in the year ended December 31, 2021, partially offset by projects which started in 2021 and provided $18.2 million.

Energy Storage Segment

Revenues attributable to our Energy Storage segment for the year ended December 31, 2021 were $30.4 million compared to $15.8 million for the year ended December 31, 2020, representing a 92.1% increase.  The increase was mainly due to an increase of $7.6 million in revenues from the Rabbit Hill battery energy storage facility primarily as a result of the February 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. This led to a significant increase in the Responsive Reserve Service market price. In addition, we recorded $9.4 million of revenues from the Pomona energy storage asset that we acquired in July 2020 in the year ended December 31, 2021, compared to $4.8 million in the year ended December 31, 2020.

Total Cost of Revenues

Electricity Segment

Total cost of revenues attributable to our Electricity segment for the year ended December 31, 2021 was $337.0 million, compared to $300.1 million for the year ended December 31, 2020, representing a 12.3% increase. This increase  was primarily attributable to: (i) the consolidation of the Dixie Valley and Beowawe power plants which were acquired on July 13, 2021 as part of the TG Geothermal Portfolio, LLC, acquisition, with cost of revenues of $13.6 million and $2.3 million, respectively; (ii) cost of revenues related to the enhancement of the Steamboat Hills power plant in June 2020 and (iii) the resumption of  operations of the Puna power plant to 25MW in the third quarter of 2021, which was offset by business interruption insurance recovery of $15.5 million in the year ended December 31, 2021, compared to $7.8 million in the year ended December 31, 2020, as further discussed in Note 1 to the consolidated financial statements. As a percentage of total Electricity revenues, the total cost of revenues attributable to our Electricity segment for the year ended December 31, 2021 was 57.5%, compared to 55.4% for the year ended December 31, 2020. This increase was primarily attributable to the decrease in gross profit relating to higher operational costs in some of our power plants. The cost of revenues attributable to our international power plants was 20% of our Electricity segment cost of revenues for the year ended December 31, 2021.

Product Segment

Total cost of revenues attributable to our Product segment for the year ended December 31, 2021 was $41.4 million, compared to $114.9 million for the year ended December 31, 2020, representing a 64.0% decrease from the prior period. This decrease was primarily attributable to the decrease 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, 2021 was 88.2%, compared to 77.6% for the year ended December 31, 2020.

Energy Storage Segment

Cost of revenues attributable to our Energy Storage segment for the year ended December 31, 2021 were $20.4 million as compared to $14.1 million in the year ended December 31, 2020.  Cost of revenues attributable to our Energy Storage segment for the year ended December 31, 2021 includes $6.6 million from the acquisition of the Pomona energy storage asset that was acquired in July 2020, compared to $3.1 million in the year ended December 31, 2020. The Energy Storage segment includes cost of revenues related to the delivery of energy storage, demand response and energy management services.

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Research and Development Expenses

Research and development expenses for the year ended December 31, 2021 were $4.1 million, compared to $5.4 million for the year ended December 31, 2020, represent a 23.5% decrease. The decrease is mainly attributable to the timing of new development projects that took place during the year ended December 31, 2021 compared to the corresponding period in 2020.

Selling and Marketing Expenses

Selling and marketing expenses for the year ended December 31, 2021 were $15.2 million, compared to $17.4 million for the year ended December 31, 2020, representing 12.6% decrease.  The decrease was mainly due to a decrease in sales commissions as a result of the decrease in Product segment revenues. Selling and marketing expenses constituted 2.3% of total revenues for the year ended December 31, 2021, compared to 2.5%, for the year ended December 31, 2020.

General and Administrative Expenses

General and administrative expenses for the year ended December 31, 2021 were $75.9 million, compared to $60.2 million for the year ended December 31, 2020, representing 26.0% increase. The increase was primarily attributable to: (i) the provision for doubtful debts of $3.0 million relating to imbalance charges from the grid operator in respect of our demand response operation that we may be unable to collect due to the February power crisis in Texas; (ii) $5.6 million transaction costs including $4.7 million related to the TG Geothermal Portfolio, LLC, acquisition, on July 13, 2021; (iii) legal costs associated with the investigation by the Special Committee, and  (iv) a gain of $1.3 million from the sale of concession in the year ended December 31, 2020.  General and administrative expenses for the year ended December 31, 2021 constituted 11.4% of total revenues for such period, compared to 8.5%, for the year ended December 31, 2020.

Business Interruption Insurance Income

Business interruption insurance income for the year ended December 31, 2021 was $0.2 million compared to $20.7 million for the year ended December 31, 2020, representing a 98.8% decrease. Business interruption insurance income for the years ended December 31, 2021 and 2020 is attributable to business interruption recovery relating to the Puna power plant.

Interest Expense, Net

Interest expense, net, for the year ended December 31, 2021 was $82.7 million, compared to $78.0 million for the year ended December 31, 2020, representing a 6.0% increase from the prior period. This increase was primarily due to (i)$125.0 million of proceeds from Bank Hapoalim Loan received in July 2021; (ii) $50.0 million of proceeds from HSBC Bank Loan received in July 2021; (iii) $259 million related to Finance Lease liability related to the TG Geothermal Portfolio, LLC, acquisition, in July, 2021; (iv) $100.0 million of proceeds from Bank Discount Loan received in September 2021, and (v) a $2.9 million increase in interest related to sale of tax benefits, partially offset by a $4.2 million increase in interest capitalized to projects and lower interest expense as a result of principal payments of long term debt.

Derivatives and Foreign Currency Transaction Gains (Losses)

Derivatives and foreign currency transaction losses for the year ended December 31, 2021 were $14.7 million, compared to gains of $3.8 million for the year ended December 31, 2020. Derivatives and foreign currency transaction losses for the year ended December 31, 2021 includes 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 as described above. Derivatives and foreign currency transaction gains for the year ended December 31, 2020 were attributable primarily to gains from foreign currency forward contracts which were not accounted for as hedge transactions.

Income Attributable to Sale of Tax Benefits

Income attributable to the sale of tax benefits for the year ended December 31, 2021 was $29.6 million, compared to $25.7 million for the year ended December 31, 2020. Tax equity is a form of financing used for renewable energy projects. 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. In 2021, we entered into the Steamboat Hills tax monetization transaction which contributed $1.1 million of income during the year.

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Other Non-Operating Income (Expense), Net

Other non-operating income, net for the year ended December 31, 2021 was $0.1 million, compared to $1.4 million for the year ended December 31, 2020. Other non-operating income for the year ended December 31, 2020 mainly includes income of $0.6 million for property damage recovery related to the Puna power plant.

Income from operations, before income taxes and equity in earnings of investees

Income from operations, before income taxes and equity in earnings of investees for the year ended December 31, 2021 was $103.6 million, compared to $168.7 million, as described above for the year ended December 31, 2020, representing a 38.6% decrease. This decrease was mainly driven by: (i) the decrease in product segment gross margin as a result from the decrease in product segment revenues; (ii) the business interruption insurance income of $20.7 million for the year ended December 31, 2020; and (iii) $14.5 million in losses relating to the hedge transaction,

Income Taxes

Income tax provision for the year ended December 31, 2021, was $24.9 million, a decrease of $42.2 million compared to an income tax provision of $67.0 million for the year ended December 31, 2020. Our effective tax rate for the year ended December 31, 2021 and 2020, was 24.0% and 39.7%, respectively. The effective rate differs from the federal statutory rate of 21% for the year ended December 31, 2021 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. The decrease in the effective tax rate for the year ended December 31, 2021 as compared to the year ended December 31, 2020 is primarily driven by reduced GILTI income inclusion, benefit due to approved qualification as an "Innovation Promoting Enterprise" by the Israeli Innovation Authority, and additional releases in the Company's valuation allowance in the current year.

Equity in Earnings (losses) of investees, net

Equity in losses of investees, net in the year ended December 31, 2021, was $2.6 million, compared to equity in earnings of investees, net of $0.1 million in the year ended December 31, 2020. Equity in earnings (losses) of investees, net is mainly derived from our 12.75% share in the earnings or losses in Sarulla. Due to a combination of lower asset performance and a non-cash write-off of deferred tax assets, SOL, the project company, is currently evaluating the viability of a long term remediation plan to restore generation and change the project PPA's energy rates. We are following the remediation plans in Sarulla  as well as the accounting impact and its implication on our financial statements on our investment in Sarulla.

Net Income attributable to the Company’s Stockholders

Net income attributable to the Company’s stockholders for the year ended December 31, 2021 was $62.1 million, compared to $85.5 million for the year ended December 31, 2020, which represents a decrease of $23.4 million. This decrease was attributable to the decrease of $25.7 million in net income which was affected by all the explanations above, partially offset by a decrease of $2.4 million in net income attributable to noncontrolling interest, mainly due to lower business interruption recovery of the Puna power plant in Hawaii, in the year ended December 31, 2021, compared to the year ended December 31, 2020.

Comparison of the year ended December 31, 2020 and the year ended December 31, 2019

A discussion of changes in our results of operations in 2020 compared to 2019 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, 2020, filed with the SEC on February 26, 2021, which 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, private offerings 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.

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As of December 31, 2021, we had access to: (i) $239.3 million in cash and cash equivalents, of which $39.2 million was held by our foreign subsidiaries; (ii) $43.3 million of investment in debt securities; and (iii) $450.6 million of unused corporate borrowing capacity under existing lines of credit with different commercial banks.

As of December 31, 2021, $185.0 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 2022 include approximately $515.0 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 $386.3 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 $640.0 million in capital expenditures for construction of new projects and enhancements to our existing power plants, of which we had invested $324.0 million as of December 31, 2021. We expect to invest approximately $230.0 million in 2022 and the remaining approximately $86.0 million on thereafter.

In addition, we estimate approximately $285.0 million in additional capital expenditures in 2022 to be allocated as follows: (i) approximately $145.0 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 $42.0 million for maintenance of capital expenditures to our operating power plants; (iii) approximately $90.0 million for the construction and development of storage projects; and (iv) approximately $8.0 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.

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; (ii) 12-month debt, net of cash, cash equivalents, and short-term bank deposits to Adjusted EBITDA ratio not to exceed 6.0; and (iii) dividend distributions not to exceed 50% of net income in any calendar year. As of December 31, 2021: (i) total equity was $1,998.5 million and the actual equity to total assets ratio was 45.2%; and (ii) the 12-month debt, net of cash and cash equivalents to Adjusted EBITDA ratio was 4.02. During the year ended December 31, 2021, we distributed interim dividends in an aggregate amount of $27.0 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, 2021, as a result of the overdue debt outstanding of ENEE as further described under Note 1 to the consolidated financial statements, Platanares is restricted from making certain equity distributions. Additionally, as of December 31, 2021, we did not meet the covenants related to the DAC 1 Senior Secured Notes and Prudential Capital Group – Nevada non-recourse loan which resulted in certain equity distribution restrictions from the related subsidiaries.

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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, 2021.The credit termination date is June 30, 2022.

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 31,2021: (i) the actual 12-month debt to EBITDA ratio was 2.4; (ii) the 12-month DSCR was 4.8; and (iii) the distribution leverage ratio was 0.66. 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, 2021, letters of credit in the aggregate amount of $59.1 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, 2022. On December 31, 2021, the aggregate amount available under the credit agreement was $ 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, 2021: (i) the actual 12-month debt to EBITDA ratio was 2.4; (ii) the 12-month DSCR was 4.8; and (iii) the distribution leverage ratio was 0.66. 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, 2021, letters of credit in the aggregate amount of $35.0 million were issued and outstanding under the committed portion of this credit agreement and $2.5 million under the uncommitted portion of the agreement.

Future minimum payments

Future minimum payments under long-term obligations as of December 31, 2021, 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 and (ii) full-recourse debt incurred by us or our subsidiaries for general corporate purposes.

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

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

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

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Non-Recourse and Limited-Recourse Third-Party Debt

(1) 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, 2021, 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

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

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Financing Liability

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

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 $5.7 million as of December 31, 2021. 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, 2021:

Historical Cash Flows

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

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For the Year Ended December 31, 2021

Net cash provided by operating activities for the year ended December 31, 2021 was $258.8 million, compared to $265.0 million for the year ended December 31, 2020. The net decrease of $6.2 million resulted primarily from (i) a decrease in costs and estimated earnings in excess of billing on uncompleted contracts, net of $12.9 million in the year ended December 31, 2021, compared to $22.2 million in the year ended December 31, 2020, as a result of timing of billing to our customers; (ii) a decrease in accounts payable and accrued expenses of $21.9 million in the year ended December 31, 2021, compared to $5.4 million in the year ended December 31, 2020, mainly due to timing of payments to our supplier; (iii) an increase in prepaid expenses and other of $19.1 million in the year ended December 31, 2021, compared to $2.7 million in the year ended December 31, 2020, mainly due to tax prepayments of OSL. The decrease was partially offset by a decrease of $26.7 million in receivables in the year ended December 31, 2021 compared to  $3.5 million in the year ended December 31, 2020 because of timing of collections from our customers.

Net cash used in investing activities for the year ended December 31, 2021 was $638.2 million, compared to $386.0 million for the year ended December 31, 2020. The principal factors that affected the increase in our net cash used in investing activities during the year ended December 31, 2021 were: (i) capital expenditures of $419.3 million, compared to $320.7 million during the year ended December 31, 2020, primarily for our facilities under construction that support our growth plan; (ii) cash paid for the purchase transaction of Terra-Gen for a total consideration of $171.0 million, net compared to $43.4 million related to the purchase of the Pomona energy storage asset in California; (iii) purchases of marketable securities of $60.1 million in 2021 compared to none in 2020; and (iv) an investment in an unconsolidated company of $6.4 million in 2021 compared to $21.0 million in 2020, partially offset by maturity of marketable securities of $16.3 million.

Net cash provided by financing activities for the year ended December 31, 2021 was $186.4 million, compared to $503.5 million provided by financing activities for the year ended December 31, 2020. The principal factors that affected the decrease in net cash provided by financing activities were: (i) $275.0 million proceeds from long term loans from banks in 2021 compared to $419.3 million during 2020 and (ii) $339.5 million proceeds from issuance of common stock, net in 2020 compared to none in 2021, partially offset by: (i) the repayment of long-term debt in the amount of $93.0 million in 2021 compared to $135.4 million in 2020; (ii) repayments of commercial paper and revolving credit lines with banks of $50.0 million and $40.6 million, respectively, in 2020 compared to none in 2021; (iii) $37.1 million of proceeds from the sale of limited liability company interest, net of transaction costs in 2021 compared to none in 2020.

For the Year Ended December 31, 2020

A discussion of changes in our cash flows in 2020 compared to 2019 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, 2020, filed with the SEC on February 26, 2021, which 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 and amortization. We calculate Adjusted EBITDA as net income before interest, taxes, depreciation and amortization, 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, and (vi) 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 its 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.

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, 2021 was $76.1 million, compared to $101.8 million for the year ended December 31, 2020 and $93.5 million for the year ended December 31, 2019.

Adjusted EBITDA for the year ended December 31, 2021 was $401.4 million, compared to $420.2 million for the year ended December 31, 2020 and $384.3 million for the year ended December 31, 2019.

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The following table reconciles net income to EBITDA and adjusted EBITDA for the years ended December 31, 2021, 2020 and 2019:

•         Adjusted EBITDA for the fiscal year 2021 decreased 4.5% compared to fiscal 2020, due primarily to a $27.6 million reduction in gross profit of the Product segment, offset partially by improved performance of the Electricity and Energy Storage segments.

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, 2021, the credit facility has an outstanding balance of $939.9 million.  Our proportionate share in the SOL credit facility is $119.8 million. Additionally, in March and September 2021, Sarulla failed to meet its debt service coverage ratio under the credit facility agreement due to lower performance of the power plants. The Sarulla power plant complex has been 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. To address these issues, the project management developed a Long-Term Recovery Plan ("LTRP") that includes drilling of additional wells and various equipment modifications. The LTRP is expected to be implemented starting in 2022, pending approval by the lenders. Additional initiatives are also undergoing in an effort to strengthen the Sarulla project's financial position, including potential tariff changes. We are following the remediation plans in Sarulla  as well as the potential accounting impact on our consolidated financial statements in respect with our equity investment in Sarulla. As of December 31, 2021, the carrying value of our equity investment in SOL is $69.0 million.

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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 are determined by reference to the relevant power purchaser’s SRAC. 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.

As of December 31, 2021, 98.0% of our consolidated long-term debt was fixed rate debt and therefore was not subject to interest rate volatility risk and 2.0% of our long-term debt was floating rate debt, exposing us to interest rate risk in connection therewith. As of December 31, 2021, $34.0 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 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 KES similar to the tax liability, however any change in the exchange rate in the KES versus the USD 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/USD 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. 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, 2021 and 2020 by a hypothetical 10% and calculating the resulting change in the fair values.

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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, 2021 and 2020 are presented below:

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

While we expect that the long term inflation rate will not be a significant, we recently experienced an increase in raw material costs, which put pressure on our operating margins in the Product segment and increased our cost to build our own power plants. 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 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. 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 our power plants, thereby increasing our operating costs in the Product segment. We are more likely to be able to offset all or part of this inflationary impact through our project pricing. With respect to power plants that we build for our own electricity production, inflationary pricing may impact our operating costs which may be partially offset in the pricing of the new long-term PPAs that we negotiate.

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Contractual Obligations and Commercial Commitments

The following tables set forth our material contractual obligations as of December 31, 2021 (in thousands):

The table above does not reflect unrecognized tax benefits of $5.7 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 $135.0 million, the timing of which is uncertain and other long-term liabilities of $5.0 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.

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

We have historically been able to collect on substantially all of our receivable balances. As of December 31, 2021, the amount overdue from KPLC in Kenya was $25.5 million of which $22.9 million was paid in January and February of 2022. These amounts represent an average of 63 days overdue. 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/political events).

In Honduras, as of December 31, 2021, the total amount overdue from ENEE was $20.7 million of which $2.9 million was collected in February 2022.  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

The U.S. federal government encourages production of electricity from geothermal resources or solar energy through certain tax subsidies:

We are also permitted to depreciate most of the cost of a new geothermal power plant. In cases where we claim the one-time 30% (or 10%) 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. Projects that were placed in service in 2016 and 2017 were eligible for “bonus” depreciation of 50% of the cost of that equipment in the year the power plant was placed in service. Following the Tax Act, 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 Act and determine if an election is appropriate as it relates to our business needs.

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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.