ORMAT TECHNOLOGIES, INC. 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.
• The Puna power plant resumed operations in
operated at a level of 25 MW. We continue with drilling and workovers into
2022 to increase generation. In 2019, we reached an agreement with HELCO and
signed a new PPA that is currently subject to PUC approval. The new PPA
extends the current term 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. 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.
• InOctober 2021 , we completed a$38.9 million tax equity partnership
transaction for the
future payments of approximately
continue to operate and maintain the power plant and will receive
substantially all of the attributable cash flow generated by the power plant.
• In
joint venture company, PT Toka Tindung Geothermal ("TTG") with PT Archi
to explore the potential of geothermal energy prospects in the Bitung area of
the North Sulawesi region, especially within the Toka Tindung gold mine
concession area. Under the TTG shareholder agreement, subject to completion of
certain conditions, Archi has the option to acquire 25% of the project while
Ormat will hold the remaining shares.
• In
for a 10 MW geothermal air-cooled
acquisition and development of renewable energy projects in
the San Jacinto facility in Telica, Leon, Republic of Nicaragua .
• In
agreement with Pacific Gas and Electric Company (PG&E) for the 20MW/40MWh
will be located adjacent to and will utilize existing infrastructure from the
operating
facility will provide 10MW of Resource Adequacy to PG&E and will also
participate in the energy and ancillary services markets run by the
we will undertake the EPC of this project and expect the project to begin
commercial operation in the third quarter of 2022.
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• In
subsidiary of
working capital and assumed cash of approximately
the equity interests in entities holding the below described assets and
assumed debt and associated finance obligation with a fair value of
approximately
operating geothermal power plants in
geothermal power plant, one of the largest geothermal power plants in
and the 11.5 MW Beowawe geothermal power plant, as well as the rights to
high resource potential, and an underutilized transmission line, capable of
handling between 300MW and 400MW of 230KV electricity, connecting
to California .
• In
PPAs entered into between various independent power producers and KPLC,
including
task force recommended to the President that KPLC review its contracts and
attempt renegotiation with Independent Power Producers to secure reductions in
PPA tariffs within existing contractual arrangements.
the task force following release of the report.
• In
the fifth largest electricity provider in
provider of 100% renewable energy to customers in the nation. Under terms of
the agreement, effective
clean, renewable energy from
in
had a shorter remaining duration and was subject to an early termination
option. This is
additional agreements in the future as CPA pursues aggressive goals to provide
renewable energy to southern California .
• In
geothermal power plant in
2021, increases the power plant net capacity by 15 MW, bringing the entire
Phase 3 power plant continues to sell its electricity under the current
25-year long term portfolio power purchase agreement with SCPPA.
• In
Vallecito Battery Energy Storage System ("Vallecito BESS"). The Vallecito BESS
provides local resource adequacy to SCE under a 20-year energy storage
resource adequacy agreement. In addition, the facility will provide ancillary
services and energy optimization through participation in merchant markets run
by the CAISO.
• In
independent directors to investigate, among other things, certain claims made
in a report published by a short seller regarding the Company's compliance
with anti-corruption laws. The Special Committee is working with outside legal
counsel to investigate the claims made. All members of the Special Committee
are "independent" in accordance with our Corporate Governance Guidelines, the
NYSE listing standards and
general. We are also providing information as requested by the
related to the claims.
• Since the beginning of 2021 we released five energy storage systems for
construction with a total of 139MW/399MWh, which are located in
California ,Texas andOhio . We are targeting commercial operation of 89MW/124MWh in 2022 and the rest in 2023. • InFebruary 2021 , extreme weather conditions inTexas resulted in a
significant increase in demand for electricity on the one hand and a decrease
in electricity supply in the region on the other hand. On
the
Emergency Alert Level 3 ("EEA 3") prompting rotating outages in
ultimately led to a significant increase in the Responsive Reserve Service
("RRS") market prices, where the Company operates its Rabbit Hill battery
energy storage facility which provides ancillary services and energy
optimization to the wholesale markets managed by
supply shortage,
from
the Rabbit Hill storage facility to provide RRS. As a result, the Company
incurred losses of approximately
from a hedge transaction in relation to its inability to provide RRS during
that period. Starting
facility resumed operation at full capacity. In addition, the Company recorded
a provision for approximately
imbalance charges from the grid operator in respect of its demand response
operation as it estimated it is probable it may be unable to collect such
receivables. The provision for uncollectible receivables is included in
"General and administrative expenses" in the condensed consolidated statements
of operations and comprehensive income for the first quarter of 2021. The
Company is currently in discussions with
imbalance charges and revenue allocated to its Demand Response services and
customers, the outcome of which may impact the final amount.
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Table of Contents 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, includingIsrael , 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:
• In our Electricity segment, almost all of our revenues in 2021 were generated
under long term contracts and the majority of contracts have a fixed energy
rate. As a result, despite logistical and other challenges, COVID-19 caused
only limited impact on our Electricity segment. Nevertheless, growth in the
Electricity segment was and continues to be adversely impacted by delays in
receiving the required development and construction permits, as well as the
implications of global and local restrictions on our ability to procure and
transport raw materials and increases in the cost of raw materials and
transportation.
• Our Product segment revenues are generated from sales of products and services
pursuant to contracts, under which we have a right to payment for any product
that was produced for the customer. Recognition of revenue under these
contracts is impacted by delays in the progress of the third-party projects
into which our products and services are incorporated. In 2021, COVID-19
outbreaks resulted in the extended shutdown of certain businesses in certain
regions, delays in the supply and increases in the cost of raw materials and
components that we purchased for our equipment manufacturing, and increases in
the cost of marine transportation. The cost increases limited our ability to
secure new purchase orders from potential customers and led to a reduction in
our operating margins, which in turn negatively impacted our profitability. We
had a product backlog of
revenue recognition for the period between
2022, compared to $33.4 million as of February 25, 2021 .
• Our Energy Storage segment generates revenues mainly from participating in the
energy and ancillary services markets, run by regional transmission operators
and independent system operators in the various markets where our assets
operate. Therefore, the revenues these assets generate are directly impacted
by the prevailing market prices for energy and/or ancillary services.
Nevertheless, we have experienced and are experiencing supply chain
difficulties, as well as an increase in the cost raw materials and batteries,
which may impact our ability to complete the projects on time and increases
overall project costs.
• In addition, we experience delays in the permitting for new projects in all
segments that may result in contractual penalties and cause a delay in those
projects.
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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":
• There has been increased demand for energy generated from geothermal and other
renewable resources in
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
primarily by further commitment to, and implementation of, state RPS and
greenhouse gas reduction initiatives.
• The
certain actions which are supportive of the industry for climate solutions. In
facilities being eligible for the ITC for geothermal as well as solar
projects. The new
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
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 Electricity segment, we expect intense domestic competition from the
solar, hybrid solar and energy storage and wind power generation industries to
intensify. While we believe the expected demand for renewable energy will be
large enough to accommodate increased competition, any such increase in
competition, including increasing amounts of renewable energy under contract
and reduction in energy storage costs are contributing to a reduction in
electricity prices. However, despite increased competition from the solar and
wind power generation industries, we believe that firm and flexible, base-load
electricity, such as geothermal-based energy, will continue to be an important
source of renewable energy in areas with commercially viable geothermal
resources.
• In the Product segment, we see new opportunities for business in
the
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.
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Table of Contents 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 endedDecember 31, 2021 were derived from PPAs with fixed price components, we have variable price PPAs inCalifornia andHawaii , 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:
? The energy rates under the 12 MW Heber 2 power plant PPA in
primarily based on fluctuations in natural gas prices. We used our right under
the PPA and sent a termination notice to SCE. We are currently negotiating a
new long-term PPA for the project following a request for bid we issued in
2021.
? The prices paid for electricity pursuant to the 25 MW PPA for the
in
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. The PPA is
subject to PUC approval.
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: % of Revenues for Period Revenues Indicated Year Ended December 31, Year Ended December 31, 2021 2020 2019 2021 2020 2019 Revenues: (Dollars in thousands) Electricity$ 585,771 $ 541,393 $ 540,333 88.3 % 76.8 % 72.4 % Product 46,920 148,125 191,009 7.1 21.0 25.6 Energy Storage 30,393 15,824 14,702 4.6 2.2 2.0 Total revenues$ 663,084 $ 705,342 $ 746,044 100.0 % 100.0 % 100.0 % 77
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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:
% of Revenues for Period
Revenues Indicated
Year Ended December 31, Year Ended December 31,
2021 2020 2019 2021 2020 2019
Electricity Segment: (Dollars in thousands)
United States $ 404,303 $ 341,399 $ 333,797 69.0 % 63.1 % 61.8 %
International 181,468 199,994 206,536 31.0 36.9 38.2
Total $ 585,771 $ 541,393 $ 540,333 100.0 % 100.0 % 100.0 %
Product Segment:
United States $ 5,414 $ 5,800 $ 30,562 11.5 % 3.9 % 16.0 %
International 41,506 142,325 160,447 88.5 96.1 84.0
Total $ 46,920 $ 148,125 $ 191,009 100.0 % 100.0 % 100.0 %
Energy Storage Segment:
United States $ 30,393 $ 15,824 $ 13,597 100.0 % 100.0 % 92.5 %
International - - 1,105 0.0 0.0 7.5
Total $ 30,393 $ 15,824 $ 14,702 100.0 % 100.0 % 100.0 %
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 ourCalifornia power plants, our principal cost of revenues also includes transmission charges and scheduling charges. In some of ourNevada 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 endedDecember 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:
• 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.
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• 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$50.7 million and$51.5 million atDecember 31, 2021 and 2020, 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.
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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 endedDecember 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.
•
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.
on an annual basis, which the Company performs on
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, an entity 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
-
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.
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• 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 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.
Year Ended December 31,
2021 2020 2019
(Dollars in thousands, except earnings per share data)
Revenues:
Electricity $ 585,771 $ 541,393 $ 540,333
Product 46,920 148,125 191,009
Energy storage 30,393 15,824 14,702
Total revenues 663,084 705,342 746,044
Cost of revenues:
Electricity 337,019 300,059 312,835
Product 41,374 114,948 145,974
Energy storage 20,353 14,060 17,912
Total cost of revenues 398,746 429,067 476,721
Gross profit (loss)
Electricity 248,752 241,334 227,498
Product 5,546 33,177 45,035
Energy storage 10,040 1,764 (3,210 )
Total gross profit 264,338 276,275 269,323
Operating expenses:
Research and development expenses 4,129 5,395 4,647
Selling and marketing expenses 15,199 17,384 15,047
General and administrative expenses 75,901 60,226 55,833
Business interruption insurance income (248 ) (20,743 ) -
Operating income 169,357 214,013 193,796
Other income (expense):
Interest income 2,124 1,717 1515
Interest expense, net (82,658 ) (77,953 ) (80,384 )
Derivatives and foreign currency transaction
gains (losses) (14,720 ) 3,802 624
Income attributable to sale of tax benefits 29,582 25,720 20,872
Other non-operating income (expense), net (134 ) 1,418 880
Income from operations before income tax and
equity in earnings (losses) of investees 103,551 168,717 137,303
Income tax provision (24,850 ) (67,003 ) (45,613 )
Equity in earnings (losses) of investees,
net (2,624 ) 92 1,853
Net Income 76,077 101,806 93,543
Net income attributable to noncontrolling
interest (13,985 ) (16,350 ) (5,448 )
Net income attributable to the Company's
stockholders $ 62,092 $ 85,456 $ 88,095
Earnings per share attributable to the
Company's stockholders:
Basic: $ 1.11 $ 1.66 $ 1.73
Diluted: $ 1.10 $ 1.65 $ 1.72
Weighted average number of shares used in
computation of earnings per share
attributable to the Company's stockholders:
Basic 56,004 51,567 50,867
Diluted 56,402 51,937 51,227
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Results as a percentage of revenues
Year Ended December 31,
2021 2020 2019
Revenues:
Electricity 88.3 % 76.8 % 72.4 %
Product 7.1 21.0 25.6
Energy storage 4.6 2.2 2.0
Total revenues 100.0 100.0 100.0
Cost of revenues:
Electricity 57.5 55.4 57.9
Product 88.2 77.6 76.4
Energy storage 67.0 88.9 121.8
Total cost of revenues 60.1 60.8 63.9
Gross profit (loss)
Electricity 42.5 44.6 42.1
Product 11.8 22.4 23.6
Energy storage 33.0 11.1 (21.8 )
Total gross profit 39.9 39.2 36.1
Operating expenses:
Research and development expenses 0.6 0.8 0.6
Selling and marketing expenses 2.3 2.5 2.0
General and administrative expenses 11.4 8.5 7.5
Business interruption insurance income 0.0 (2.9 ) 0.0
Operating income 25.5 30.3 26.0
Other income (expense):
Interest income 0.3 0.2 0.2
Interest expense, net (12.5 ) (11.1 ) (10.8 )
Derivatives and foreign currency
transaction gains (losses) (2.2 ) 0.5 0.1
Income attributable to sale of tax
benefits 4.5 3.6 2.8
Other non-operating income (expense), net 0.0 0.2 0.1
Income from continuing operations before
income tax and equity in earnings
(losses) of investees 15.6 23.9 18.4
Income tax provision (3.7 ) (9.5 ) (6.1 )
Equity in earnings (losses) of investees,
net (0.4 ) - 0.2
Net Income 11.5 14.4 12.5
Net income attributable to noncontrolling
interest (2.1 ) (2.3 ) (0.7 )
Net income attributable to the Company's
stockholders 9.4 % 12.1 % 11.8 %
Comparison of the Year Ended December 31, 2021 and the Year Ended December 31,
2020
Total Revenues
Year Ended Year Ended
December December
31, 2021 31, 2020 Increase (Decrease)
(Dollars in millions)
Electricity segment revenues $ 585.8 $ 541.4 $ 44.4 8.2 %
Product segment revenues 46.9 148.1 (101.2 ) (68.3 )
Energy Storage segment revenues 30.4 15.8 14.6 92.1
Total Revenues $ 663.1 $ 705.3 $ (42.2 ) (6.0 )%
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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Table of Contents Product Segment Revenues attributable to our Product segment for the year endedDecember 31, 2021 were$46.9 million , compared to$148.1 million for the year endedDecember 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 inTurkey ,New Zealand andChile , which started in 2019, and provided$98.3 million in revenue recognized during the year endedDecember 31, 2020 , compared to$10.1 million in the year endedDecember 31, 2021 , and projects inTurkey , which started in 2020, and provided$23.6 million in revenue recognized during the year endedDecember 31, 2020 , compared to zero in the year endedDecember 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 endedDecember 31, 2021 were$30.4 million compared to$15.8 million for the year endedDecember 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 inTexas , 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 thePomona energy storage asset that we acquired inJuly 2020 in the year endedDecember 31, 2021 , compared to$4.8 million in the year endedDecember 31, 2020 . Total Cost of Revenues Year Ended Year Ended December 31, December 31, 2021 2020 Increase (Decrease) (Dollars in millions)
Electricity segment cost of revenues
$ 37.0 12.3 % Product segment cost of revenues 41.4 114.9 (73.6 ) (64.0 ) Energy Storage segment cost of revenues 20.4 14.1 6.3 44.8 Total Cost of Revenues$ 398.8 $ 429.1 $ (30.3 ) (7.1 )% Electricity Segment Total cost of revenues attributable to our Electricity segment for the year endedDecember 31, 2021 was$337.0 million , compared to$300.1 million for the year endedDecember 31, 2020 , representing a 12.3% increase. This increase was primarily attributable to: (i) the consolidation of theDixie Valley andBeowawe power plants which were acquired onJuly 13, 2021 as part of theTG 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 theSteamboat Hills power plant inJune 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 endedDecember 31, 2021 , compared to$7.8 million in the year endedDecember 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 endedDecember 31, 2021 was 57.5%, compared to 55.4% for the year endedDecember 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 endedDecember 31, 2021 . Product Segment Total cost of revenues attributable to our Product segment for the year endedDecember 31, 2021 was$41.4 million , compared to$114.9 million for the year endedDecember 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 endedDecember 31, 2021 was 88.2%, compared to 77.6% for the year endedDecember 31, 2020 . Energy Storage Segment Cost of revenues attributable to our Energy Storage segment for the year endedDecember 31, 2021 were$20.4 million as compared to$14.1 million in the year endedDecember 31, 2020 . Cost of revenues attributable to our Energy Storage segment for the year endedDecember 31, 2021 includes$6.6 million from the acquisition of thePomona energy storage asset that was acquired inJuly 2020 , compared to$3.1 million in the year endedDecember 31, 2020 . The Energy Storage segment includes cost of revenues related to the delivery of energy storage, demand response and energy management services. 85
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Research and Development Expenses
Research and development expenses for the year endedDecember 31, 2021 were$4.1 million , compared to$5.4 million for the year endedDecember 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 endedDecember 31, 2021 compared to the corresponding period in 2020.
Selling and Marketing Expenses
Selling and marketing expenses for the year endedDecember 31, 2021 were$15.2 million , compared to$17.4 million for the year endedDecember 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 endedDecember 31, 2021 , compared to 2.5%, for the year endedDecember 31, 2020 .
General and Administrative Expenses
General and administrative expenses for the year endedDecember 31, 2021 were$75.9 million , compared to$60.2 million for the year endedDecember 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 inTexas ; (ii)$5.6 million transaction costs including$4.7 million related to theTG Geothermal Portfolio, LLC , acquisition, onJuly 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 endedDecember 31, 2020 . General and administrative expenses for the year endedDecember 31, 2021 constituted 11.4% of total revenues for such period, compared to 8.5%, for the year endedDecember 31, 2020 .
Business Interruption Insurance Income
Business interruption insurance income for the year endedDecember 31, 2021 was$0.2 million compared to$20.7 million for the year endedDecember 31, 2020 , representing a 98.8% decrease. Business interruption insurance income for the years endedDecember 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 endedDecember 31, 2021 was$82.7 million , compared to$78.0 million for the year endedDecember 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 inJuly 2021 ; (ii)$50.0 million of proceeds from HSBC Bank Loan received inJuly 2021 ; (iii)$259 million related to Finance Lease liability related to theTG Geothermal Portfolio, LLC , acquisition, in July, 2021; (iv)$100.0 million of proceeds from Bank Discount Loan received inSeptember 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 endedDecember 31, 2021 were$14.7 million , compared to gains of$3.8 million for the year endedDecember 31, 2020 . Derivatives and foreign currency transaction losses for the year endedDecember 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 ofGeorgetown, Texas inFebruary 2021 as described above. Derivatives and foreign currency transaction gains for the year endedDecember 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 endedDecember 31, 2021 was$29.6 million , compared to$25.7 million for the year endedDecember 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 theSteamboat Hills tax monetization transaction which contributed$1.1 million of income during the year. 86
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Other Non-Operating Income (Expense), Net
Other non-operating income, net for the year endedDecember 31, 2021 was$0.1 million , compared to$1.4 million for the year endedDecember 31, 2020 . Other non-operating income for the year endedDecember 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 endedDecember 31, 2021 was$103.6 million , compared to$168.7 million , as described above for the year endedDecember 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 endedDecember 31, 2020 ; and (iii)$14.5 million in losses relating to the hedge transaction, Income Taxes Income tax provision for the year endedDecember 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 endedDecember 31, 2020 . Our effective tax rate for the year endedDecember 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 endedDecember 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 endedDecember 31, 2021 as compared to the year endedDecember 31, 2020 is primarily driven by reduced GILTI income inclusion, benefit due to approved qualification as an "Innovation Promoting Enterprise" by theIsraeli 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 endedDecember 31, 2021 , was$2.6 million , compared to equity in earnings of investees, net of$0.1 million in the year endedDecember 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 endedDecember 31, 2021 was$62.1 million , compared to$85.5 million for the year endedDecember 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 inHawaii , in the year endedDecember 31, 2021 , compared to the year endedDecember 31, 2020 .
Comparison of the year ended
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 endedDecember 31, 2020 , filed with theSEC onFebruary 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 ofDecember 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 ofDecember 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 ofDecember 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$8.0 million for enhancements to our production facilities. We expect to finance these requirements with: (i) the sources of liquidity described above; (ii) positive cash flows from our operations; and (iii) future project financings and re-financings (including construction loans and tax equity). Management believes that, based on the current stage of implementation of our strategic plan, the sources of liquidity and capital resources described above will address our anticipated liquidity, capital expenditures, and other investment requirements.
Letters of Credits under the Credit Agreements
Some of our customers require our project subsidiaries to post letters of credit in order to guarantee their respective performance under relevant contracts. We are also required to post letters of credit to secure our obligations under various leases and licenses and may, from time to time, decide to post letters of credit in lieu of cash deposits in reserve accounts under certain financing arrangements. In addition, our subsidiary,Ormat Systems , is required from time to time to post performance letters of credit in favor of our customers with respect to orders of products. Credit Agreements Issued Issued and Termination Amount Outstanding as of Date December 31, 2021 (Dollars in millions) Committed lines for credit and letters of credit$ 468.0 $ 77.9 March 2022-Nov 2023 Committed lines for letters of credit 155.0 94.5 April 2022-August 2023 Non-committed lines - 12.6 October 2022-December 2022 Total$ 623.0 $ 185.0 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 ofDecember 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 endedDecember 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 ofDecember 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 ofDecember 31, 2021 , we did not meet the covenants related to the DAC 1Senior Secured Notes and Prudential Capital Group -Nevada non-recourse loan which resulted in certain equity distribution restrictions from the related subsidiaries. 88
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Table of Contents Credit Agreements
Credit Agreement with
Ormat Nevada has a credit agreement withMUFG Union Bank under which it has an aggregate available credit of up to$60.0 million as ofDecember 31 , 2021.The credit termination date isJune 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 guaranteeOrmat 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 ofDecember 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 ofOrmat Nevada in favor of Union Bank. As ofDecember 31, 2021 , letters of credit in the aggregate amount of$59.1 million were issued and outstanding under this credit agreement.
Credit Agreement with
Ormat Nevada has a credit agreement withHSBC Bank USA , N.A for one year with annual renewals. The current expiration date of the facility under this credit agreement isOctober 31, 2022 . OnDecember 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 guaranteeOrmat 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 ofDecember 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 ofOrmat Nevada in favor of HSBC.
As of
Future minimum payments Future minimum payments under long-term obligations as ofDecember 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. 89
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Non-Recourse and Limited-Recourse Third-Party Debt
Loan Line of Amount Interest Maturity Related Location
Credit Outstanding Rate Date Projects
as of
December 31, 2021
(Dollars in millions)
McGinness
Hills
phase 1
OFC 2 Senior Secured and
Notes - Series A $ 151.7 $ 79.6 4.69% 2032 Tuscarora United States
McGinness
OFC 2 Senior Secured Hills
Notes - Series B 140.0 93.8 4.61% 2032 phase 2 United States
Olkaria III Financing Olkaria
Agreement with DFC - III
Tranche 1 85.0 42.5 6.34% 2030 Complex Kenya
Olkaria III Financing Olkaria
Agreement with DFC - III
Tranche 2 180.0 90.0 6.29% 2030 Complex Kenya
Olkaria III Financing Olkaria
Agreement with DFC - III
Tranche 3 45.0 24.2 6.12% 2030 Complex Kenya
Amatitlan Financing 42.0 19.3 LIBOR+4.35% 2027 Amatitlan Guatemala
(1)
Don A.
Don A. Campbell Campbell
Senior Secured Notes 92.5 67.9 4.03% 2033 Complex United States
Neal Hot
Springs
Prudential Capital and Raft
Group Idaho Loan (2) 20.0 16.8 5.8% 2023 River United States
U.S. Department of Neal Hot
Energy loan (3) 96.8 39.0 2.61% 2035 Springs United States
Prudential Capital
Group Nevada Loan 30.7 25.1 6.75% 2037 San Emidio United States
Platanares Loan with
DFC 114.7 88.1 7.02% 2032 Platanares Honduras
Viridity - 23.5 14.7 LIBOR+3.5% 2026 Plumsted United States
Plumstriker Striker
Geothermie Bouillante Geothermie
(4) 8.9 5.9 1.52% 2026 Bouillante Guadeloupe
Geothermie Bouillante Geothermie
(4) 8.9 7.7 1.93% 2026 Bouillante Guadeloupe
Total $ 1,039.7 $ 614.6
(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
(2) Secured by equity interest.
(3) Secured by the assets.
(4) Loan in Euros and issued amount is
Full-Recourse Third-Party Debt
Amount Amount Interest Maturity
Loan Issued Outstanding as of Rate Date
December 31, 2021
(Dollars in millions)
Hapoalim Loan $ 125.0 $ 116.1 3.45% June 2028
HSBC Loan 50.0 50.0 3.45% July 2028
Discount Loan 100.0 100.0 2.90% September 2029
Senior Unsecured Bonds
Series 3 218.0 218.0 4.45% September 2022
Senior Unsecured Bonds
Series 4 (1) 289.8 321.5 3.35% June 2031
Senior Unsecured Loan 1 100.0 95.8 4.80% March 2029
Senior Unsecured Loan 2 50.0 47.9 4.60% March 2029
Senior Unsecured Loan 3 50.0 47.9 5.44% March 2029
DEG Loan 2 50.0 32.5 6.28% June 2028
DEG Loan 3 41.5 28.4 6.04% June 2028
Total $ 1,074.3 $ 1,058.1
(1) Bonds issued in total aggregate principal amount of
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Financing Liability
Amount
Outstanding as
of Annual Maturity
December 31,
Loan 2021 Interest Rate Date (1)
(Dollar in
millions)
Financing Liability - Dixie Valley $ 252.9 2.55 % March 2033
(1) final maturity date of the financing liability is assuming execution of the
buy-out option in
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$5.7 million as ofDecember 31, 2021 . This liability is included in long-term liabilities in our consolidated balance sheet, because we generally do not anticipate that settlement of the liability will require payment of cash within the next 12 months. We are not able to reasonably estimate when we will make any cash payments required to settle this liability. Dividends We have adopted a dividend policy pursuant to which we currently expect to distribute at least 20% of our annual profits available for distribution by way of quarterly dividends. In determining whether there are profits available for distribution, our Board will take into account our business plan and current and expected obligations, and no distribution will be made that in the judgment of our Board would prevent us from meeting such business plan or obligations. The following are the dividends declared by us during the past two years, as ofDecember 31, 2021 : Dividend Amount per Date Declared Share Record Date Payment Date November 6, 2019$ 0.11 November 20, 2019 December 4, 2019 February 25, 2020$ 0.11 March 12, 2020 March 26, 2020 May 8, 2020$ 0.11 May 21, 2020 June 2, 2020 August 4, 2020$ 0.11 August 18, 2020 September 1, 2020 November 4, 2020$ 0.11 November 18, 2020 December 2, 2020 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 Historical Cash Flows The following table sets forth the components of our cash flows for the relevant periods indicated: Year Ended December 31, 2021 2020 2019 (Dollars in thousands)
Net cash provided by operating activities
$ 236,493 Net cash used in investing activities (638,193 ) (385,969 ) (254,538 ) Net cash provided by (used in) financing activities 186,385 503,478 (5,765 ) Translation adjustments on cash and cash equivalents (348 ) 1,154 (575 ) Net change in cash and cash equivalents and restricted cash and cash equivalents$ (193,334 ) $ 383,668 $ (24,385 ) 91
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For the Year Ended
Net cash provided by operating activities for the year endedDecember 31, 2021 was$258.8 million , compared to$265.0 million for the year endedDecember 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 endedDecember 31, 2021 , compared to$22.2 million in the year endedDecember 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 endedDecember 31, 2021 , compared to$5.4 million in the year endedDecember 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 endedDecember 31, 2021 , compared to$2.7 million in the year endedDecember 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 endedDecember 31, 2021 compared to$3.5 million in the year endedDecember 31, 2020 because of timing of collections from our customers. Net cash used in investing activities for the year endedDecember 31, 2021 was$638.2 million , compared to$386.0 million for the year endedDecember 31, 2020 . The principal factors that affected the increase in our net cash used in investing activities during the year endedDecember 31, 2021 were: (i) capital expenditures of$419.3 million , compared to$320.7 million during the year endedDecember 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 thePomona energy storage asset inCalifornia ; (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 endedDecember 31, 2021 was$186.4 million , compared to$503.5 million provided by financing activities for the year endedDecember 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
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 endedDecember 31, 2020 , filed with theSEC onFebruary 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 inthe United States , orU.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 withU.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 endedDecember 31, 2021 was$76.1 million , compared to$101.8 million for the year endedDecember 31, 2020 and$93.5 million for the year endedDecember 31, 2019 .
Adjusted EBITDA for the year ended
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The following table reconciles net income to EBITDA and adjusted EBITDA for the
years ended
Year Ended December 31,
2021 2020 2019
(Dollars in thousands)
Net income $ 76,077 $ 101,806 $ 93,543
Adjusted for:
Interest expense, net (including
amortization of deferred financing costs) 80,534 76,236 78,869
Income tax provision (benefit) 24,850 67,003
45,613
Adjustment to investment in an unconsolidated company: our proportionate share in interest expense, tax and depreciation and amortization in Sarulla complex 14,680 11,549
13,089
Depreciation and amortization 177,930 151,371
143,242
EBITDA 374,071 407,965
374,356
Mark-to-market on derivative instruments 741 (1,192 ) (1,402 ) Stock-based compensation 9,168 9,830
9,358
Reversal of a contingent liability (418 ) - - Allowance for bad debts related to February power crisis in Texas 2,980 - - Hedge losses resulting from February power crisis in Texas 9,133 - - Loss from extinguishment of liability - - 468 Merger and acquisition transaction costs 5,635 2,279
1,483
Legal settlement expenses - 1,277 - Tender-related deposits write-off 134 - - Adjusted EBITDA$ 401,444 $ 420,159 $ 384,263 • 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.
OnMay 2014 , the Sarulla consortium ("SOL") closed$1,170 million in financing. As ofDecember 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 andSeptember 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 ofDecember 31, 2021 , the carrying value of our equity investment in SOL is$69.0 million . 93
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Table of Contents 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 theHeber 2 power plant in theHeber 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 thePuna Complex . As ofDecember 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 ofDecember 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+ byStandard & Poor's Ratings Services ). We are also exposed to foreign currency exchange risk, in particular the fluctuation of theU.S. dollar versus the NIS inIsrael 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. InKenya , 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 theU.S. dollar. Substantially all of our PPAs in the international markets are eitherU.S. dollar-denominated or linked to theU.S. dollar except for our operations onGuadeloupe , where we own and operate the Bouillante power plant which sells its power under a Euro-denominated PPA with Électricité deFrance 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. OnJuly 1, 2020 , we concluded an auction tender and accepted subscriptions for senior unsecured bonds comprised ofNIS 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 atDecember 31, 2021 and 2020 by a hypothetical 10% and calculating the resulting change in the fair values. 94
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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
Assuming a 10% Assuming a 10%
Increase in Rates Decrease in Rates
As of December 31, As of December 31,
Change in the Fair Value
Risk 2021 2020 2021 2020 of
(In thousands)
Foreign Currency Forward
Foreign Currency $ (2,719 ) $ (1,996 ) $ 3,324 $ 2,439 Contracts
Interest Rate $ (1,131 ) $ - $ 1,148 $ - Hapoalim Loan
Interest Rate $ (557 ) $ - $ 566 $ - HSBC Loan
Interest Rate $ (1,119 ) $ - $ 1,131 $ - Discount Loan
Interest Rate $ (3,394 ) $ - $ 3,465 $ - Financing Liability
Interest Rate $ (3,069 ) $ (3,025 ) $ 3,146 $ 3,090 OFC 2 Senior Secured Notes
Interest Rate $ (2,946 ) $ (3,193 ) $ 3,025 $ 3,273 DFC Loan
Interest Rate $ (226 ) $ (311 ) $ 231 $ 318 Amatitlan Loan
Interest Rate $ (3,833 ) $ (4,278 ) $ 3,880 $ 4,313 Senior Unsecured Bonds
Interest Rate $ (494 ) $ (586 ) $ 505 $ 599 DEG 2 Loan
Interest Rate $ (1,286 ) $ (1,266 ) $ 1,324 $ 1,299 DAC 1 Senior Secured Notes
Migdal Loan and the
Additional Migdal Loan and
the Second Addendum MigdalInterest Rate$ (3,135 ) $ (3,194 ) $ 3,214 $ 3,270 Loan Interest Rate$ (920 ) $ (941 ) $ 965 $ 983 San Emidio Loan Interest Rate$ (539 ) $ (444 ) $ 550 $ 450 DOE Loan Interest Rate$ (88 ) $ (151 ) $ 89$ 153 Idaho Holdings Loan Interest Rate$ (2,035 ) $ (2,146 ) $ 2,100 $ 2,209 Platanares DFC Loan Interest Rate$ (389 ) $ (452 ) $ 397 $ 461 DEG 3 Loan Interest Rate$ (121 ) $ (179 ) $ 123 $ 181 Plumstriker Loan Interest Rate $ - $ - $ - $
- Commercial Paper
Interest Rate
InJuly 2019 , theUnited 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 inJune 2023 in order to allow a transition period mainly for contracts that already exist using LIBOR. Additionally, theFCA has stated that no new contracts usingU.S. dollar LIBOR should be entered into afterDecember 31, 2021 . TheU.S. Federal Reserve , in conjunction with the Alternative Reference Rates Committee, a steering committee comprised of largeU.S. financial institutions, is considering replacingU.S. dollar LIBOR with a new index calculated by short-term repurchase agreements, backed byTreasury 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 ourU.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 theMcGinness 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. 95
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Contractual Obligations and Commercial Commitments
The following tables set forth our material contractual obligations as of
Payments Due by Period
Remaining
Total 2022 2023 2024 2025 2026 Thereafter
Long-term debt and
financing liabilities -
principal $ 1,925,530 $ 386,289 $ 189,103 $ 253,044 $ 167,193 $ 168,468 $ 761,433
Interest on long-term
debt and financing
liabilities (1) 363,163 78,827 61,489 53,795 44,373 37,185 87,496
Finance lease
obligations 10,249 3,326 1,549 854 693 514 3,313
Operating lease
obligations 29,604 3,079 2,329 2,043 1,656 1,519 18,978
Benefits upon retirement
(2) 15,606 4,526 92 263 951 664 9,110
Asset retirement
obligation 84,891 - - - - - 84,891
Purchase commitments (3) 249,167 249,167 - - - - -
$ 2,678,210 $ 725,214 $ 254,562 $ 309,999 $ 214,866 $ 208,350 $ 965,221 (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, 2021, total obligations related to such supplier agreements were
approximately
to construction-in-process). All such obligations are payable in 2022.
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 andNevada 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. 96
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The Company's revenues from its primary customers as a percentage of total
revenues are as follows:
Year Ended December 31,
2021 2020 2019
Southern California Public Power Authority ("SCPPA") 23.7 % 20.6 % 17.9 %
Sierra Pacific Power Company and Nevada Power Company 18.6 17.5 16.8
Kenya Power and Lighting Co. Ltd. ("KPLC") 15.5 16.4 16.3
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
• PTC - the PTC rules provide an income tax credit for each kWh of electricity
produced from certain renewable energy sources, including geothermal, and sold
to an unrelated person during a taxable year. The PTC was first introduced in
1992 and has since been revised a number of times. The PTC, which in 2021 was
10 years on the net electricity output sold to third parties after the project
is first placed in service. The tax extender package signed into law in
ordinarily be placed in service within four years after the end of the year in
which construction started or show continued construction to qualify for
PTC. The PTC is not available for power produced from geothermal resources for
projects that started construction on or after January 1, 2022 .
• The ITC rules have been amended a number of times. A qualified new geothermal
power plant in
would be eligible to claim an ITC of 30% of the project eligible cost. New
solar projects that were under construction by
for a 30% ITC. The credit will phase down to 26% for solar PV projects
starting construction by the end of 2022 and to 22% for solar PV projects
starting construction in 2023. Projects that were under construction before
these deadlines must be placed in service by
the ITC at these rates. Solar projects placed in service after
2025 will only qualify for a 10% ITC. Under current tax rules, any unused tax
credit has a one-year carry back and a twenty-year carry forward.
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 underIsrael's Law for Encouragement of Capital Investments, 1959 (the Investment Law), with respect to two of its investment programs through 2011. InJanuary 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. InJanuary 2021 ,Ormat Systems received an approval from theIsraeli 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.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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.
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