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 2020 Revenues
For the year ended
For the year endedDecember 31, 2020 , Electricity segment revenues were$541.4 million , compared to$540.3 million for the year endedDecember 31, 2019 , an increase of 0.2%. Product segment revenues for the year endedDecember 31, 2020 were$148.1 million , compared to$191.0 million for the year endedDecember 31, 2019 , a decrease of 22.5%. Energy Storage segment revenues for the year endedDecember 31, 2020 were$15.8 million , compared to$14.7 million for the year endedDecember 31, 2019 an increase of 7.6%. 78
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During the years endedDecember 31, 2020 and 2019, our consolidated power plants generated 6,043,993 MWh and 6,238,272 MWh, respectively, decreased of 3.1%. The average prices during the years endedDecember 31, 2020 and 2019 were$89.6 and$86.6 per MWh, respectively. For the year endedDecember 31, 2020 , our Electricity segment generated 76.8% of our total revenues (72.4% in 2019), while our Product segment generated 21.0% of our total revenues (25.6% in 2019), and our Energy Storage segment generated 2.2% of our total revenues (2.0% in 2019). For the year endedDecember 31, 2020 , approximately 98.2% of our Electricity segment revenues were from PPAs with fixed energy rates which are not affected by fluctuations in energy commodity prices. We have variable price PPAs inCalifornia andHawaii , which provide for payments based on the local utilities' avoided cost, which 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 PPAs in
the
between 30 to 40 MW, change primarily based on fluctuations in natural gas
prices.
? 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.
To comply with obligations under their respective PPAs, certain of our project
subsidiaries are structured as special purpose, bankruptcy remote entities and
their assets and liabilities are ring-fenced. Such assets are not generally
available to pay our debt, other than debt at the respective project subsidiary
level. However, these project subsidiaries are allowed to pay dividends and make
distributions of cash flows generated by their assets to us, subject in some
cases to restrictions in debt instruments, as described below.
Electricity segment revenues are also subject to seasonal variations and are
affected by higher-than-average ambient temperatures, as described below under
"Seasonality".
Revenues attributable to our Product segment are based on the sale of equipment,
EPC contracts and the provision of various services to our customers. Product
segment revenues may vary from period to period because of the timing of our
receipt of purchase orders and the progress of our equipment manufacturing and
execution of the relevant project.
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 , the 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.
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 and similar
to the Product segment when we provide services to third parties.
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Table of Contents Recent Developments
The most significant recent developments for our company and business during 2019 and 2020 to date are described below.
• As of
operating at approximately 13 MW. On the field side, the Company connected one
new production well to the power plant and the Company continues its field
recovery work, which includes drilling new wells and expects a gradual
increase in generation to full capacity by the middle of 2021, assuming field
recovery is successfully achieved.
• In December 2020 , we announced that we completed the acquisition of a
shovel-ready energy storage asset in
asset from
design, build, own and operate a 25 MW BESS project at the site.
targeting commercial operation of the BESS before the end of 2021.
• In December Ormat announced several departures and appointments in its
executive management team:
•
President-Electricity Segment on
certain duties until his June 30, 2022 retirement date.
• Shimon Hatzir was appointed to the role of Executive Vice
President-Electricity Segment, effective April 1, 2021 .
• Shlomi Argas, Executive Vice President-Operations and Products of
appointed to serve as a President of Ormat , effective January 1, 2021 .
• In October and December of 2020, the Company entered into two settlement
agreements with the KRA in relation to three the NoAs which were previously
issued by the KRA, totaling approximately
penalties. The settlement agreements covered tax years from 2013 through 2019,
included deferral of tax benefits to be utilized in years subsequent to 2019
in an amount of approximately
approximately
in 2020. This concluded all open audits and NoAs with the KRA.
• In
shares of our common stock at a price of
the underwriters' option to purchase an additional 622,500 shares of common
stock at the same price. We intend to use the net proceeds from the offering
for general corporate purposes, including working capital and capital
expenditures, and for potential acquisitions, including complementary
businesses, technologies or assets.
• In
each for 50% of our 5 MW / 20 MWh Tierra Buena battery energy storage project
currently under development in
agreements were signed with two Community Choice Aggregators,
Energy Authority and Valley Clean Energy.
• In
geothermal power plant in
that was outstanding from prior years.
• In
in
The
with
and ancillary services markets run by the California Independent System
Operator .
• In
that were issued in New Israeli Shekels and were converted to
using a cross-currency swap transaction (the "Swap") at an effective fixed
interest rate of 4.34%. The
bear, prior to the Swap, a fixed interest rate of 3.35% per annum, payable
semi-annually starting
installments starting
the terms and conditions of the trust instrument that will govern the Bonds.
The Bonds received a rating of ilAA- from Maloot S&P in
outlook. In April and
new corporate debt from existing lenders.
• In
increased its generating capacity by 19MW to a total of 84MW. Enhancement work
included the replacement of all old generating unit equipment with new,
state-of-the-art equipment and resource modifications. The new equipment will
increase the productivity and efficiency of the power plant and is expected to
reduce maintenance costs per kWh.
sell its electricity under the current 25-year long term portfolio power
purchase agreement with SCPPA, with 100% of the capacity going to the Los
Angeles Department of Water and Power . 80
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• In
Battery Energy Storage System ("BESS") facility, providing required ancillary
services and energy optimization to the wholesale markets managed by
The facility is located in the
provide approximately 10 MW of fast responding capacity to the
• In
2020, after six years of service and became a member of
Directors and its chairman.
Blachar as the Company's Chief Executive Officer and Mr.
Chief Financial Officer.
• In
("SVCE") and
MBCP will each purchase 7 MW (for a total of 14 MW) of power generated by the
expected 30 MW Casa Diablo-IV ("CD4") geothermal project located in Mammoth
Lakes,
years and have a fixed MWh price, which includes energy, capacity,
environmental attributes, and all other ancillary benefits. The remaining 16
MW of generating capacity will be sold under an additional PPA with SCPPA,
which was signed in early 2019. The CD4 power plant is expected to be on-line
in Q1 2022, and will be the first geothermal power plant built within the
CAISO balancing authority in the last 30 years and will be the first in
COVID 19 Update
In
The Company implemented significant measures both to comply with government requirements and to preserve the health and safety of its employees. These measures include working remotely where possible and operating separate shifts in its power plants, manufacturing facilities and other locations while trying to continue operations as close to full capacity in all locations. During the year and subsequently, the Company's power plants, manufacturing facility and storage facilities have been operating at close to full capacity and there has been no material impact on our operations as a result of these measures. With respect to our employees, we have not laid-off or furloughed any employees due to the COVID-19 and continued to pay full salaries.
We experienced the following impacts on our segment operations:
• In our Electricity segment, almost all of our revenues in 2020 were generated
under long term contracts and the majority have a fixed energy rate. As a
result, despite logistical and other challenges, we experienced limited impact
of COVID-19 on our Electricity segment. Nevertheless, we received two notices
declaring a force majeure event in
both had an immaterial impact on our revenues and removed. In addition, we
experienced a higher rate of curtailments during the first half of 2020 byKPLC in the Olkaria complex that was reduced in the second half of 2020. The
impact of the curtailments is limited because of the structure of the PPA
which secures the vast majority of our revenues with fixed capacity payments
and is unrelated to the electricity actually generated (in 2019 and 2020,
capacity payments represented 70.1% and 74.4% of our revenues, respectively).
ENEE has initiated discussions with several IPPs, including
potential changes in their existing PPAs. However, our Platanares geothermal
power plant has one of the lowest rates of renewable energy in the country,
and we expect this fact to have positive implications for our discussions with
ENEE. In addition, our future growth in the Electricity segment is and would
be adversely impacted by delays we are experiencing in receiving the required
development and construction permits, as well as by the implications of global
and local restrictions on our ability to procure raw materials and ship to our
products. Furthermore, our future growth in the Electricity segment might be
adversely impacted by a lack of funding for projects, a decrease in demand for
electricity, delays in permitting and the implications of global and local
restrictions on our ability to procure raw material and ship our products.
• 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. We experienced delays
and significant cost increases in one of the projects in the Product segment
that adversely impacted our results of operations during 2020. We had a
product backlog of
revenues for the period between
compared to
decline in backlog resulted mainly from the impact of COVID-19 and the
unwillingness of potential customers to enter into new commitments at this
time. Nevertheless, for the reasons set out above, restrictions on travel and
because our customers are deferring their decision to purchase, we expect that
2021 product segment revenues will be significantly lower than revenues of
2020.
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• 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 is directly impacted by
the prevailing market prices for energy and/or ancillary services.
• In addition, we experience delays in the permitting for new projects in all
segments that may create penalties and cause a delay in those projects.
Despite our efforts to provide insight into the performance of our business and
the trends affecting it, as of the date of this filing, significant uncertainty
exists concerning the magnitude of the impact and duration of the COVID-19
pandemic. We may continue to become subject to any of the following impacts:
• limitations on the ability of our suppliers to obtain raw materials that are
required for the manufacturing of the products we either sell to third parties
or build for ourselves or to meet delivery requirements and commitments that
may result in penalty payments;
• impact on our efforts to sign new contracts for our Product segment due to
operational and travel restrictions and availability of our customers and
their willingness to enter into new agreements;
• limitations on the ability of our customers to pay us on a timely basis;
• additional declarations of COVID-19 as force majeure by our customers and
suppliers;
• a reduction in the demand for electricity and for our products;
• change in regulations, taxes and levies that may affect our operations and
cost structure;
• risk of infection among employees that may impact the day-to-day operations;
• delays in obtaining the required permits that may create penalties and impact
our ability to implement our growth plan;
• limited ability to oversee remote operation due to travel restrictions.
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:
• 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
further commitment to, and implementation of, state RPS and greenhouse gas
reduction initiatives.
• 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.
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• In the Electricity segment, we expect intense domestic competition from the
solar, hybrid solar and energy storage and wind power generation industries to
continue and increase as well as increased competition from the solar combined
with storage projects. 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 as well as any further decline in natural gas prices
attributable to increased production 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 in
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
• The average price per MWh, which is one of the metrics some investors may use
to evaluate power plant revenues, can fluctuate from period to period. Based
on our Electricity segment, we earned, on average,
2020 and 2019, respectively. Oil and natural gas prices, together with other
factors that affect our Electricity segment revenues, could cause changes in
our average price per MWh in the future.
•
geothermal industry worldwide, mainly due to governmental and regulatory
support.
capacity of over 1,600 MW. In 2020 we had less revenue exposure to the Turkish
market, due to a slowdown in project development in that market, with further
impacts from the COVID-19 outbreak. The continued deterioration in that
Turkish economy, devaluation in the Turkish Lira and increase in local
interest rates or a decline in government support for the development ofgeothermal power in the country could affect local demand for the geothermal
equipment and services we provide, collection from our customers or the prices
we may charge for such equipment and services. In
plan and regulation for renewable energy generation in
the updated FIT is lower than the previous one. This recent update and the
economic status of the country lead us to estimate that the slowdown in
development of new sites will continue. In addition, the impact of threatened
or actual
competitiveness for the geothermal equipment and services we provide in the
Turkish market, in turn decreasing our Product segment profit margins, cash
flows and financial condition. For the year ended
derived 9% and 44% of our Total revenues and Product revenues, respectively,
from our Turkish operations. We are monitoring any change in the political and
business environments that may affect our future business and operations in
the country.
•
produce several power plant components that entitle our customers to increased
incentives under the renewable energy laws. The use of local equipment in
renewable energy based generating facilities in
facilities to significant benefits under Turkish law, provided such facilities
have obtained an RER Certificate from EMRA, which requires the issuance of a
local certificate. If we do not obtain the local certificate, then some of our
customers under the relevant supply agreements in
RER Certificate based on the equipment we supply to them, and we will be
required to make a payment to such customers equal to the amount of the
expected lost benefit.
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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 . Revenues attributable to our Electricity segment are derived from the sale of electricity from our power plants pursuant to long-term PPAs. While approximately 98.2% of our Electricity revenues for the year endedDecember 31, 2020 were derived from PPAs with fixed price components and the balance from variable price PPAs inCalifornia andHawaii . 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. Revenues attributable to our Product segment 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. 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 also pursue financial instruments, where appropriate, to hedge some of the merchant risk. 84
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The following table sets forth a breakdown of our revenues for the years
indicated:
Revenues % ofRevenues for Period Indicated
Year Ended December 31 ,
Year Ended
2020 2019 2018 2020 2019 2018
(Dollars in thousands)
Revenues:
Electricity $ 541,393 $ 540,333 $ 509,879 76.8 % 72.4 % 70.9 %
Product 148,125 191,009 201,743 21.0 25.6 28.0
Energy Storage 15,824 14,702 7,645 2.2 2.0 1.1
Total revenues $ 705,342 $ 746,044 $ 719,267 100.0 % 100.0 % 100.0 %
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:
Revenues % of Revenues for Period Indicated
Year Ended December 31, Year Ended December 31,
2020 2019 2018 2020 2019 2018
(Dollars in thousands)
Electricity Segment:
United States $ 341,399 $ 333,797 $ 305,962 63.1 % 61.8 % 60.0 %
International 199,994 206,536 203,917 36.9 38.2 40.0
Total $ 541,393 $ 540,333 $ 509,879 100.0 % 100.0 % 100.0 %
Product Segment:
United States $ 5,800 $ 30,562 $ 14,999 3.9 % 16.0 % 7.4 %
International 142,325 160,447 186,744 96.1 84.0 92.6
Total $ 148,125 $ 191,009 $ 201,743 100.0 % 100.0 % 100.0 %
Energy Storage Segment:
United States $ 15,824 $ 13,597 $ 7,645 100.0 % 92.5 % 100.0 %
International - 1,105 - 0.0 7.5 0.0
Total $ 15,824 $ 14,702 $ 7,645 100.0 % 100.0 % 100.0 %
In 2020, 2019 and 2018, 49%, 49% and 54% of our revenues were derived from
international operations of all 3 segments combined, respectively, and our
international operations were more profitable than our U.S. operations in each
of those years. A substantial portion of international revenues came from Kenya
and Turkey 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 63%, 62% and 60% of our total Electricity segment for the years
ended December 31, 2020 , 2019 and 2018, respectively. However, domestic
operations in our Electricity segment have higher costs of revenues and expenses
than the foreign operations in our Electricity segment. 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. They 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 2020 the international operations of the
segment accounted for 51% of our total gross profits, 70% of our net income and
45% of our EBITDA. However, financing costs related to the international
projects are higher than financing costs related to our domestic activity.
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Product Segment. Our Product segment foreign revenues were 96%, 84% and 93% of our total Product segment revenues for the years endedDecember 31, 2020 , 2019 and 2018, respectively. Our Product segment foreign activity also benefits from lower costs of revenues and expenses than Product segment domestic activity such as labor and transportation costs. Accordingly, our Product segment foreign activity contributes more than our Product segment domestic activity to our pre-tax income from operations. 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 theHeber 2 power plant in theHeber Complex , theMammoth Complex and theNorth Brawley power plant inCalifornia , theRaft River power plant inIdaho and theNeal Hot Springs power plant inOregon , 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.
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 3.8% and 4.1% of Electricity segment revenues for the years endedDecember 31, 2020 and 2019, 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 attributable to providing services to our customers, direct costs associated with software development and the direct cost of BESS that we own. Direct costs include labor costs of our network operations center, the labor of software development effort and the labor associated with operations and maintenance of owned BESS. Cost of revenues attributable to our Energy Storage segment also include cost of equipment sold to customers in delivering our automated demand response and software services at a customer's location. 86
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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 gross margins. As aresult, 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 delivery is made, as
applicable.
• Property, Plant and Equipment. We capitalize all costs associated with the
acquisition, development and construction of power plant facilities. Major
improvements are capitalized and repairs and maintenance (including major
maintenance) costs are expensed. We estimate the useful life of our power
plants to range between 25 and 30 years. Such estimates are made by management
based on factors such as prior operations, the terms of the underlying PPAs,
geothermal resources, the location of the assets and specific power plant
characteristics and designs. Changes in such estimates could result in useful
lives which are either longer or shorter than the depreciable lives of such
assets. We periodically re-evaluate the estimated useful life of our power
plants and revise the remaining depreciable life on a prospective basis.
We capitalize costs incurred in connection with the exploration and development of geothermal resources beginning when we acquire land rights to the potential geothermal resource. Prior to acquiring land rights, we make an initial assessment that an economically feasible geothermal reservoir is probable on that land using available data and external assessments vetted through our exploration department and occasionally outside service providers. Costs incurred prior to acquiring land rights are expensed. It normally takes two to three years from the time we start active exploration of a particular geothermal resource to the time we have an operating production well, assuming we conclude the resource is commercially viable. In most cases, we obtain the right to conduct our geothermal development and operations on land owned by the BLM, various states or with private parties. In consideration for certain of these leases, we may pay an up-front non-refundable bonus payment which is a component of the competitive lease process. This payment and other related costs are capitalized and included in construction-in-process. 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$51.5 million and$84.6 million atDecember 31, 2020 and 2019, respectively. Included in these amounts atDecember 31, 2020 and 2019, respectively, are$5.3 million and$17.0 million , respectively, which relate to up-front bonus payments. 87
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• Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of. We
evaluate long-lived assets, such as property, plant and equipment and
construction-in-process for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. Factors which could trigger an impairment include, among others,
significant underperformance relative to historical or projected future
operating results, significant changes in our use of assets or our overall
business strategy, negative industry or economic trends, a determination that
an exploration project will not support commercial operations, a determination
that a suspended project is not likely to be completed, a significant increase
in costs necessary to complete a project, legal factors relating to our
business or when we conclude that it is more likely than not that an asset
will be disposed of or sold.
We test our operating plants that are operated together as a complex for
impairment at the complex level because the cash flows of such plants result
from significant shared operating activities. For example, the operating power
plants in a complex are managed under a combined operation management generally
with one central control room that controls all of the power plants in a complex
and one maintenance group that services all of the power plants in a complex. As
a result, the cash flows from individual plants within a complex are not largely
independent of the cash flows of other plants within the complex. We test for
impairment of our operating plants which are not operated as a complex, as well
as our projects under exploration, development or construction that are not part
of an existing complex, at the plant or project level. To the extent an
operating plant becomes part of a complex in the future, we will test for
impairment at the complex level.
Recoverability of assets to be held and used is measured by a comparison of the
carrying amount of an asset to the estimated future net undiscounted cash flows
expected to be generated by the asset. The significant assumptions that we use
in estimating our undiscounted future cash flows include (i) projected
generating capacity of the power plant and rates to be received under the
respective PPA and (ii) projected operating expenses of the relevant power
plant. Estimates of future cash flows used to test recoverability of a
long-lived asset under development also include cash flows associated with all
future expenditures necessary to develop the asset. If future cash flows are
less than the assumptions we used in such estimates, we may incur impairment
losses in the future that could be material to our financial condition and/or
results of operations.
If our assets are considered to be impaired, the impairment to be recognized is
the amount by which the carrying amount of the assets exceeds their fair value.
Assets to be disposed of are reported at the lower of the carrying amount or
fair value less costs to sell. We believe that for the year ended December 31,
2020 , 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 (on
circumstances change that would more likely than not reduce the fair value of
the reporting unit below its carrying amount. Additionally, we are 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 step one of the quantitative goodwill impairment test.
This would not preclude the entity from performing the qualitative assessment
in any subsequent period. The first step compares the fair value of the
reporting unit to its carrying value, including goodwill. In
the FASB issued ASU 2017-04, Intangibles -
which was adopted by us in 2018, under which step two of the goodwill
impairment test was eliminated. Step two measured a goodwill impairment test
by comparing the implied fair value of the reporting unit's goodwill with the
carrying amount of that goodwill. Under ASU 2017-04, Intangibles -
and Other, an entity should recognize an impairment charge for the amount by
which the carrying amount of the reporting unit exceeds its fair value as
calculated under step one described above. However, the loss recognized should
not exceed the total amount of goodwill allocated to that reporting unit.
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• Obligations Associated with the Retirement of Long-Lived Assets. We record the
fair market value of legal liabilities related to the retirement of our assets
in the period in which such liabilities are incurred. These liabilities
include our obligation to plug wells upon termination of our operating
activities, the dismantling of our power plants upon cessation of our
operations, and the performance of certain remedial measures related to the
land on which such operations were conducted. When a new liability for an
asset retirement obligation is recorded, we capitalize the costs of such
liability by increasing the carrying amount of the related long-lived asset.
Such liability is accreted to its present value each period and the
capitalized cost is depreciated over the useful life of the related asset. At
retirement, we either settle the obligation for its recorded amount or report
either a gain or a loss with respect thereto. Estimates of the costs
associated with asset retirement obligations are based on factors such as
prior operations, the location of the assets and specific power plant
characteristics. We review and update our cost estimates periodically and
adjust our asset retirement obligations in the period in which the revisions
are determined. If actual results are not consistent with our assumptions used
in estimating our asset retirement obligations, we may incur additional losses
that could be material to our financial condition or results of operations.
• Accounting for Income Taxes. Significant estimates are required to arrive at
our consolidated income tax provision. This process requires us to estimate
our actual current tax exposure and to make an assessment of temporary
differences resulting from differing 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,
2020 2019 2018
(Dollars in thousands, except per share data)
Revenues:
Electricity $ 541,393 $ 540,333 $ 509,879
Product 148,125 191,009 201,743
Energy storage 15,824 14,702 7,645
Total revenues 705,342 746,044 719,267
Cost of revenues:
Electricity 300,059 312,835 298,255
Product 114,948 145,974 140,697
Energy storage 14,060 17,912 9,880
Total cost of revenues 429,067 476,721 448,832
Gross profit (loss)
Electricity 241,334 227,498 211,624
Product 33,177 45,035 61,046
Energy storage 1,764 (3,210 ) (2,235 )
Total gross profit 276,275 269,323 270,435
Operating expenses:
Research and development expenses 5,395 4,647 4,183
Selling and marketing expenses 17,384 15,047 19,802
General and administrative expenses 60,226 55,833 47,750
Impairment charge - - 13,464
Write-off of unsuccessful exploration
activities - - 126
Business interruption insurance income (20,743 ) - -
Operating income 214,013 193,796 185,110
Other income (expense):
Interest income 1,717 1,515 974
Interest expense, net (77,953 ) (80,384 ) (70,924 )
Derivatives and foreign currency transaction
gains (losses) 3,802 624 (4,761 )
Income attributable to sale of tax benefits 25,720 20,872 19,003
Other non-operating income (expense), net 1,418 880 7,779
Income from operations before income tax and
equity in earnings (losses) of investees 168,717 137,303 137,181
Income tax (provision) benefit (67,003 ) (45,613 ) (34,733 )
Equity in earnings (losses) of investees,
net 92 1,853 7,663
Net Income 101,806 93,543 110,111
Net income attributable to noncontrolling
interest (16,350 ) (5,448 ) (12,145 )
Net income attributable to the Company's
stockholders $ 85,456 $ 88,095 $ 97,966
Earnings per share attributable to the
Company's stockholders:
Basic: $ 1.66 $ 1.73 $ 1.93
Diluted: $ 1.65 $ 1.72 $ 1.92
Weighted average number of shares used in
computation of earnings per share
attributable to the Company's stockholders:
Basic 51,567 50,867 50,643
Diluted 51,937 51,227 50,969
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Results as a percentage of revenues
Year Ended December 31,
2020 2019 2018
Revenues:
Electricity 76.8 % 72.4 % 70.9 %
Product 21.0 25.6 28.0
Energy storage 2.2 2.0 1.1
Total revenues 100.0 100.0 100.0
Cost of revenues:
Electricity 55.4 57.9 58.5
Product 77.6 76.4 69.7
Energy storage 88.9 121.8 129.2
Total cost of revenues 60.8 63.9 62.4
Gross profit (loss)
Electricity 44.6 42.1 41.5
Product 22.4 23.6 30.3
Energy storage 11.1 (21.8 ) (29.2 )
Total gross profit 39.2 36.1 37.6
Operating expenses:
Research and development expenses 0.8 0.6 0.6
Selling and marketing expenses 2.5 2.0 2.8
General and administrative expenses 8.5 7.5 6.6
Impairment charge 0.0 0.0 1.9
Business interruption insurance income (2.9 ) 0.0 0.0
Operating income 30.3 26.0 25.7
Other income (expense):
Interest income 0.2 0.2 0.1
Interest expense, net (11.1 ) (10.8 ) (9.9 )
Derivatives and foreign currency transaction
gains (losses) 0.5 0.1 (0.7 )
Income attributable to sale of tax benefits 3.6 2.8 2.6
Other non-operating income (expense), net 0.2 0.1 1.1
Income from continuing operations before
income tax and equity in earnings (losses)
of investees 23.9 18.4 19.1
Income tax (provision) benefit (9.5 ) (6.1 ) (4.8 )
Equity in earnings (losses) of investees,
net 0.0 0.2 1.1
Net Income 14.4 12.5 15.3
Net income attributable to noncontrolling
interest (2.3 ) (0.7 ) (1.7 )
Net income attributable to the Company's
stockholders 12.1 % 11.8 % 13.6 %
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Comparison of the Year EndedDecember 31, 2020 and the Year EndedDecember 31, 2019 Total Revenues Year Ended Year Ended December December 31, 2020 31, 2019 Increase (Decrease) (Dollars in millions) Electricity segment revenues$ 541.4 $ 540.3 $ 1.1 0.2 % Product segment revenues 148.1 191.0 (42.9 ) (22.5 ) Energy Storage segment revenues 15.8 14.7 1.1 7.6 Total Revenues$ 705.3 $ 746.0 $ (40.7 ) (5.5 )% Total revenues for the year endedDecember 31, 2020 were$705.3 million , compared to$746.0 million for the year endedDecember 31, 2019 , which represented a 5% decrease from the prior year period. This decrease was attributable to a$42.9 million or 22% decrease in our Product segment revenues compared to the corresponding period in 2019, as discussed below. The decrease was partially offset by a slight increase in our Electricity segment revenues and Energy Storage segment revenues. Electricity Segment Revenues attributable to our Electricity segment for the year endedDecember 31, 2020 were$541.4 million , compared to$540.3 million for the year endedDecember 31, 2019 , representing a 0.2% increase from the prior period. Power generation in our power plants decreased by 3.1% from 6,238,272 MWh for the year endedDecember 31, 2019 to 6,043,993 MWh in the year endedDecember 31, 2020 , due to the lower generation at some of our power plants, including our OREG facilities and Olkaria complex that were impacted by lower demand due to COVID-19. However, revenues remained unchanged due to higher average energy rate per MWh of our entire portfolio. Product Segment Revenues attributable to our Product segment for the year endedDecember 31, 2020 were$148.1 million , compared to$191.0 million for the year endedDecember 31, 2019 , representing a 22.5% decrease from the prior period. The decrease in our Product segment revenues was mainly due to projects inTurkey and theU.S. , which were completed in 2019 and accounted for$75.9 million in revenues in the year endedDecember 31, 2019 . The decrease was partially offset by other 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$86.6 million for the year endedDecember 31, 2019 , and other projects in mainly inTurkey , which started in 2020 and provided$29.6 million for the year endedDecember 31, 2020 . The overall decrease in Product revenues is also attributable to the impact of COVID-19 which resulted in delays in the progress of the third-party projects as well as unwillingness of potential customers to enter into new commitments. Energy Storage Segment Revenues attributable to our Energy Storage segment for the year endedDecember 31, 2020 were$15.8 million compared to$14.7 million for the year endedDecember 31, 2019 , representing a 7.6% increase. The increase was mainly driven by$4.8 million of revenues from the acquisition of thePomona energy storage asset as well as the commissioning of Rabitt Hill inTexas , offset by$2.8 million in revenues from a one-time EPC project in the year endedDecember 31, 2019 . Total Cost of Revenues Year Ended Year Ended December December 31, 2020 31, 2019 Increase (Decrease) (Dollars in millions)
Electricity segment cost of revenues
114.9 146.0 (31.0 ) (21.3 )
Energy Storage segment cost of revenues 14.1 17.9 (3.9 ) (21.5 )
Total Cost of Revenues $ 429.1 $ 476.7 $ (47.7 ) (10.0 )%
Total cost of revenues for the year ended December 31, 2020 was $429.1 million
compared to $476.7 million for the year ended December 31, 2019 , which
represented a 10.0% decrease. This decrease was attributable to a decrease of
$12.8 million , or 4.1%, in cost of revenues from our Electricity segment, a
decrease of $31.0 million , or 21.3%, in cost of revenues from our Product
segment and a decrease of $3.9 million , or 21.5%, in cost of revenues from our
Energy Storage segment, all as discussed above. As a percentage of total
revenues, our total cost of revenues for the year ended December 31, 2020
decreased to 60.8% from 63.9% for the year ended December 31, 2019 .
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Table of Contents Electricity Segment Total cost of revenues attributable to our Electricity segment for the year endedDecember 31, 2020 was$300.1 million , compared to$312.8 million for the year endedDecember 31, 2019 , representing a 4.1% decrease from the prior period. This decrease was primarily attributable to a decrease in cost of revenues at our Puna power plant that was shut down immediately following theKilauea volcanic eruption onMay 3, 2018 , as the cost of revenues at our Puna power plant for the year endedDecember 31, 2020 includes a decrease in lease expense of$5.4 million due to the termination of the lease transaction. The decrease was also due to lower operational costs in some of our power plants in the year endedDecember 31, 2020 compared to the year endedDecember 31, 2019 . Cost of revenues at our Puna power plant included business interruption recovery of$7.8 million in the year endedDecember 31, 2020 , compared to$9.3 million in the year endedDecember 31, 2019 . As a percentage of total Electricity revenues, the total cost of revenues attributable to our Electricity segment for the year endedDecember 31, 2020 was 55.4%, compared to 57.9% for the year endedDecember 31, 2019 . The cost of revenues attributable to our international power plants was 21.5% of our Electricity segment cost of revenues for the year endedDecember 31, 2020 . Product Segment Total cost of revenues attributable to our Product segment for the year endedDecember 31, 2020 was$114.9 million , compared to$146.0 million for the year endedDecember 31, 2019 , representing a 21.3% decrease from the prior period. This decrease was primarily attributable to the decrease in Product segment revenues, different product scope and different margins in the various sales contracts we entered into mainly inTurkey ,New Zealand andChile for the Product segment during these periods. As a percentage of total Product segment revenues, our total cost of revenues attributable to our Product segment for the year endedDecember 31, 2020 was 77.6%, compared to 76.4% for the year endedDecember 31, 2019 . This increase is mainly related to the higher cost of revenues related to the Nawgha project that we are constructing inNew Zealand and that was impacted, among other things, by the restrictions and limitations in the country associated with COVID-19. Energy Storage Segment Cost of revenues attributable to our Energy Storage segment for the year endedDecember 31, 2020 were$14.1 million as compared to$17.9 million in the year endedDecember 31, 2019 . The decrease was mainly driven by cost of revenues from a one-time EPC project in the amount of$2.2 million in the year endedDecember 31, 2019 , and a decrease in payroll, professional fees and consulting, offset partially by$3.1 million in cost of revenues from the acquisition of thePomona energy storage asset. The Energy Storage segment includes cost of revenues related to the delivery of energy storage services.
Research and Development Expenses
Research and development expenses for the year endedDecember 31, 2020 were$5.4 million , compared to$4.6 million for the year endedDecember 31, 2019 . The increase is mainly due to new development projects that took place during the year endedDecember 31, 2020 .
Selling and Marketing Expenses
Selling and marketing expenses for the year endedDecember 31, 2020 were$17.4 million , compared to$15.0 million for the year endedDecember 31, 2019 . The increase was mainly due to an increase in sales commissions due to different product mix and increase in marketing activities. Selling and marketing expenses constituted 2.5% of total revenues for the year endedDecember 31, 2020 , compared to 2.0%, for the year endedDecember 31, 2019 .
General and Administrative Expenses
General and administrative expenses for the year endedDecember 31, 2020 were$60.2 million , compared to$55.8 million for the year endedDecember 31, 2019 . The increase was primarily attributable to an increase in professional fees, and$1.3 million in costs associated with one of our legal claims, partially offset by a$1.3 million gain from the sale of a concession in one of our foreign locations. General and administrative expenses for the year endedDecember 31, 2020 constituted 8.5% of total revenues for such period, compared to 7.5%, excluding the earn out adjustment, for the year endedDecember 31, 2019 . 93
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Business Interruption Insurance Income
Business interruption insurance income for the year endedDecember 31, 2020 is attributable to business interruption recoveries relating to the Puna power plant. For the year endedDecember 31, 2020 , the Company recognized business insurance income of$28.6 million which was included in cost of revenues up to the amount covering the related costs and the remainder, totaling$20.7 million , was included as a business interruption insurance income under operating expenses in the consolidated statements of operations and comprehensive income. Interest Expense, Net Interest expense, net, for the year endedDecember 31, 2020 was$78.0 million , compared to$80.4 million for the year endedDecember 31, 2019 , representing a 3.0% decrease from the prior period. This decrease was primarily due to (i)$2 million decrease in interest related to the sale of tax benefits; and (ii)$7 million increase in interest capitalized to projects. The decrease was partially offset by interest expense from: (i)$79.4 million of proceeds from a senior unsecured bonds series 3 received in April andMay 2020 ; (ii)$50.0 million of proceeds from a senior unsecured loan received inApril 2020 ; and (iii)$289.9 million of proceeds from bonds series 4 received inJuly 2020 .
Derivatives and Foreign Currency Transaction Gains (Losses)
Derivatives and foreign currency transaction gains for the year endedDecember 31, 2020 were$3.8 million , compared to$0.6 million for the year endedDecember 31, 2019 . 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, 2020 was$25.7 million , compared to$20.9 million for the year endedDecember 31, 2019 . 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.
Other Non-Operating Income (Expense), Net
Other non-operating income, net for the year endedDecember 31, 2020 was$1.4 million , compared to$0.9 million for the year endedDecember 31, 2019 . 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. Other non-operating income for the year endedDecember 31, 2019 mainly includes income of$1.0 million from the sale of PG&E receivables relating to theJanuary 2019 monthly invoice which was not paid as it occurred before PG&E filed for reorganization under Chapter 11 bankruptcy.
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, 2020 was$168.7 million , compared to$137.3 million for the year endedDecember 31, 2019 , representing an 22.9% increase from the prior period. This increase was mainly driven by business interruption insurance income of$20.7 million , as described above. Income Taxes Income tax provision for the year endedDecember 31, 2020 , was$67.0 million , an increase of$21.4 million compared to an income tax provision of$45.6 million for the year endedDecember 31, 2019 . Our effective tax rate for the year endedDecember 31, 2020 and 2019, was 39.7% and 33.2%, respectively. The effective rate differs from the federal statutory rate of 21% for the year endedDecember 31, 2020 due to: (i) the mix of business in various countries with higher statutory tax rates than the federal statutory tax rate, and (ii) a net increase in the valuation allowance on deferred tax assets related toU.S. tax attributes, offset by the release of uncertain tax positions in foreign jurisdictions. 94
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Equity in Earnings (losses) of investees, net
Equity in earnings (losses) of investees, net in the year endedDecember 31, 2020 was$0.1 million , compared to$1.9 million in the year endedDecember 31, 2019 . Equity in earnings of investees, net is primarily derived from our 12.75% share in the earnings or losses in the Sarulla complex and indirect costs related to our 49% ownership interest in the Ijen project, both located inIndonesia . The decrease was mainly attributable to a lower result of operations due to well-field issues in the NIL power plant which resulted in lower generation. Sarulla is currently developing a remediation plan with a target to increase generation in the near-term. We are following the remediation plans in Sarulla as well as the potential accounting impact on our financial statements in respect of 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, 2020 was$85.5 million , compared to$88.1 million for the year endedDecember 31, 2019 , which represents a decrease of$2.6 million . This decrease was attributable to a$10.9 million in net income attributable to noncontrolling interest, which increased mainly due to the business interruption recovery of the Puna power plant inHawaii , offset partially by an increase in net income of$8.3 million , all as discussed above.
Comparison of the year ended
A discussion of changes in our results of operations in 2019 compared to 2018 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, 2019 , filed with theSEC onMarch 2, 2020 , 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. As ofDecember 31, 2020 , we had access to: (i)$448.3 million in cash and cash equivalents, of which$42.4 million was held by our foreign subsidiaries; and (ii)$389.4 million of unused corporate borrowing capacity under existing lines of credit with different commercial banks. Our estimated capital needs for 2021 include approximately$445 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$78.6 million for long-term debt repayments. As ofDecember 31, 2020 ,$190.3 million in the aggregate was outstanding under credit agreements with several banks as detailed below under "Letters of Credits under the Credit Agreements". We expect to finance these requirements with: (i) the sources of liquidity described above; (ii) positive cash flows from our operations; and (iii) future project financings and re-financings (including construction loans and tax equity). Management believes that, based on the current stage of implementation of our strategic plan, the sources of liquidity and capital resources described above will address our anticipated liquidity, capital expenditures, and other investment requirements. During 2019, we have revised our assertion to no longer indefinitely reinvest foreign funds held by our foreign subsidiaries, with the exception of a certain balance held inIsrael and have accrued the incremental foreign withholding taxes. As a result, we have further liquidity to move funds freely.
Letters of Credits under the Credit Agreements
Some of our customers require our project subsidiaries to post letters of credit in order to guarantee their respective performance under relevant contracts. We are also required to post letters of credit to secure our obligations under various leases and licenses and may, from time to time, decide to post letters of credit in lieu of cash deposits in reserve accounts under certain financing arrangements. In addition, our subsidiary,Ormat Systems , is required from time to time to post performance letters of credit in favor of our customers with respect to orders of products. Credit Agreements Issued Issued and Termination Amount Outstanding as of Date December 31, 2020 (Dollars in millions) Committed lines for credit and letters of credit$ 478.0 $ 113.6 April 2021-July 2022 Committed lines for letters of credit 145.0 66.6 April 2021-December 2021 Non-committed lines - 10.1 December 2021 Total$ 623.0 $ 190.3 95
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Table of Contents 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, 2020 : (i) total equity was$1,941.4 million and the actual equity to total assets ratio was 49.9% and (ii) the 12-month debt, net of cash and cash equivalents to Adjusted EBITDA ratio was 2.36. During the year endedDecember 31, 2020 , we distributed interim dividends in an aggregate amount of$22.5 million . The failure to perform or observe any of the covenants set forth in such agreements, subject to various cure periods, would result in the occurrence of an event of default and would enable the lenders to accelerate all amounts due under each such agreement. As described above, we are currently in compliance with our covenants with respect to the credit agreements, the loan agreements and the trust instrument, and believe that the restrictive covenants, financial ratios and other terms of any of our full-recourse bank credit agreements will not materially impact our business plan or operations. Future minimum payments Future minimum payments under long-term obligations, excluding revolving credit lines with commercial banks, as ofDecember 31, 2020 , are detailed under the caption Contractual Obligations and Commercial Commitments, below. Third-Party Debt Our third-party debt consists of (i) non-recourse and limited-recourse project finance debt or acquisition financing that we or our subsidiaries have obtained for the purpose of developing and constructing, refinancing or acquiring our various projects and (ii) full-recourse debt incurred by us or our subsidiaries for general corporate purposes. 96
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Non-Recourse and Limited-Recourse Third-Party Debt
Loan Amount Related Projects Location
Line of Outstanding Interest Maturity
Credit as of Rate Date
December 31, 2020
(Dollars in millions)
McGinness HillsOFC 2 Senior Secured phase 1 and Notes - Series A$ 151.7 $ 86.9 4.69% 2032 Tuscarora United States OFC 2 Senior Secured McGinness Hills Notes - Series B 140.0 101.3 4.61% 2032 phase 2 United States Olkaria III Financing Agreement with DFC - Olkaria III Tranche 1 85.0 47.2 6.34% 2030 Complex Kenya Olkaria III Financing Agreement with DFC - Olkaria III Tranche 2 180.0 100.6 6.29% 2030 Complex Kenya Olkaria III Financing Agreement with DFC - Olkaria III Tranche 3 45.0 26.9 6.12% 2030 Complex Kenya Amatitlan Financing (1) 42.0 22.8
LIBOR+4.35% 2027 Amatitlan
Don A.
Don A. Campbell Senior Campbell
Secured Notes 92.5 73.1 4.03% 2033 Complex United States
Prudential Capital Group Neal Hot Springs
Idaho Loan (2) 20.0 17.5 5.8% 2023 and Raft River United States
U.S. Department of
Energy loan (3) 96.8 42.0 2.61% 2035 Neal Hot Springs United States
Prudential Capital Group
Nevada Loan 30.7 26.3 6.75% 2037 San Emidio United States
Platanares Loan with DFC 114.7 96.3 7.02% 2032 Platanares Honduras
Viridity - Plumstriker 23.5 18.1 LIBOR+3.5% 2026 Plumsted+Striker United States
Geothermie Bouillante Geothermie
(4) 8.9 7.8 1.52% 2026 Bouillante Guadeloupe
Geothermie Bouillante Geothermie
(4) 8.9 9.8 1.93% 2026 Bouillante GuadeloupeTotal$ 1,039.7 $ 676.6
(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. Current interest is 5.6%.
(2) Secured by equity interest.
(3) Secured by the assets.
(4) Loan in Euros and issued amount is
Full-Recourse Third-Party Debt
Loan Amount Amount Interest Maturity
Issued Outstanding as of Rate Date
December 31, 2020
(Dollars in millions)
Senior Unsecured Bonds Series
3 $ 218.0 218.0 4.45% September 2022
Senior Unsecured Bonds Series
4 (1) $ 289.8 311.0 3.35% June 2031
Senior Unsecured Loan 1 100.0 100.0 4.80% March 2029
Senior Unsecured Loan 2 50.0 50.0 4.60% March 2029
Senior Unsecured Loan 3 50.0 50.0 5.44% March 2029
DEG Loan 2 50.0 37.5 6.28% June 2028
DEG Loan 3 41.5 32.8 6.04% June 2028
Total $ 799.3 $ 799.3
(1) Bonds issued in total aggregate principal amount of
For additional description of our long term debt, see Note 11, Long-term Debt, Credit Agreements and Commercial Paper to our consolidated financial statements.
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$2.0 million as ofDecember 31, 2020 . 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. 97
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Table of Contents 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:
Dividend
Amount per
Date Declared Share Record Date Payment Date
February 26, 2019 $ 0.11 March 14, 2019 March 28, 2019
May 6, 2019 $ 0.11 May 20, 2019 May 28, 2019
August 7, 2019 $ 0.11 August 20, 2019 August 27, 2019
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 11, 2021
Historical Cash Flows
The following table sets forth the components of our cash flows for the relevant
periods indicated:
Year Ended December 31,
2020 2019 2018
(Dollars in thousands)
Net cash provided by operating activities
$ 145,822 Net cash used in investing activities (385,969 ) (254,538 ) (342,434 ) Net cash provided by (used in) financing activities 503,478 (5,765 ) 251,131 Translation adjustments on cash and cash equivalents 1,154 (575 ) (660 ) Net change in cash and cash equivalents and restricted cash and cash equivalents$ 383,668 $ (24,385 ) $ 53,859
For the Year Ended
Net cash provided by operating activities for the year endedDecember 31, 2020 was$265.0 million , compared to$236.5 million for the year endedDecember 31, 2019 . This increase of$28.5 million resulted primarily from (i) a decrease in costs and estimated earnings in excess of billing on uncompleted contracts, net of$22.2 million in the year endedDecember 31, 2020 , compared to an increase of$11.9 million in the year endedDecember 31, 2019 , as a result of timing of billing to our customers; (ii) a decrease of$3.5 million in receivables in the year endedDecember 31, 2020 compared to an increase of$15.1 million in the year endedDecember 31, 2019 because of timing of collections from our customers. and (iii) a withholding tax payment of approximately$8 million in the year endedDecember 31, 2020 compared to$14 million in the year endedDecember 31, 2019 , because of a distribution from OSL. Net cash used in investing activities for the year endedDecember 31, 2020 was$386.0 million , compared to$254.5 million for the year endedDecember 31, 2019 . The principal factors that affected our net cash used in investing activities during the year endedDecember 31, 2020 were: (i) capital expenditures of$320.7 million , primarily for our facilities under construction that support our growth plan; (ii) cash paid for the acquisition of thePomona energy storage asset inCalifornia fromAlta Gas for a total net consideration of$43.4 million ; and (iii) an investment in an unconsolidated company of$21.0 million . 98
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Net cash provided by financing activities for the year endedDecember 31, 2020 was$503.5 million , compared to$5.8 million used in financing activities for the year endedDecember 31, 2019 . The principal factors that affected net cash provided by financing activities during the year endedDecember 31, 2020 were: (i) Proceeds from issuance of common stock, net of stock issuance costs of$339.5 million ; (ii)$289.9 million of proceeds from bonds series 4? (iii)$79.4 million of proceeds from a senior unsecured bonds series 3? and (iv)$50.0 million of proceeds from a senior unsecured loan, partially offset by: (i) the repayment of commercial paper debt of$50.0 million ; (ii) net payment of$40.6 million from our revolving credit lines with commercial banks which were withdrawn primarily to secure cash in hand in order to meet our capital needs in light of the uncertainty related to the COVID-19 pandemic, (iii) the repayment of long-term debt in the amount of$135.4 million ; (iv) a$22.5 million cash dividend payment and (v)$9.7 million cash paid to a noncontrolling interest.
For the Year Ended
A discussion of changes in our cash flows in 2019 compared to 2018 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, 2019 , filed with theSEC onMarch 2, 2020 , 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) termination fees, (ii) impairment of long-lived assets, (iii) write-off of unsuccessful exploration activities, (iv) any mark-to-market gains or losses from accounting for derivatives, (v) merger and acquisition transaction costs, (vi) stock-based compensation, (vii) gain or loss from extinguishment of liabilities, (viii) gain or loss on sale of subsidiary and property, plant and equipment and (ix) other unusual or non-recurring items. 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, 2020 was$101.8 million , compared to$93.5 million for the year endedDecember 31, 2019 and$110.1 million for the year endedDecember 31, 2018 . 99
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Adjusted EBITDA for the year ended
The following table reconciles net income to EBITDA and adjusted EBITDA for the
years ended
Year Ended December 31,
2020 2019 2018
(Dollars in thousands)
Net income $ 101,806 $ 93,543 $ 110,111
Adjusted for:
Interest expense, net (including
amortization of deferred financing costs) 76,236 78,869 69,950
Income tax provision (benefit) 67,003 45,613
34,733
Adjustment to investment in an unconsolidated company: our proportionate share in interest expense, tax and depreciation and amortization in Sarulla complex 11,549 13,089
9,184
Depreciation and amortization 151,371 143,242
127,732
EBITDA 407,965 374,356
351,710
Mark-to-market on derivative instruments (1,192 ) (1,402 ) 2,032 Stock-based compensation 9,830 9,358
10,218
Insurance proceeds in excess of assets carrying value - - (7,150 ) Termination fee - -
4,973
Impairment of goodwill, net of reversal of a contingent liability - -
3,142
Loss from extinguishment of liability - 468 - Merger and acquisition transaction costs 2,279 1,483
2,910
Settlement expenses 1,277 - - Write-off of unsuccessful exploration activities - - 126 Adjusted EBITDA$ 420,159 $ 384,263 $ 367,961 EBITDA includes the proportionate share (12.75%) of net depreciation, interest and tax expenses from our unconsolidated investment in the Sarulla complex that is accounted for under the equity method. OnMay 2014 , the Sarulla consortium ("SOL") closed$1,170 million in financing. As ofDecember 31, 2020 , the credit facility has an outstanding balance of$1,010.0 million . Our proportionate share in the SOL credit facility is$128.8 million . InOctober 2020 , Sarulla has not met its debt service coverage ratio under the credit facility agreement and is undergoing negotiations with its lenders for a waiver covering this non-compliance as well as a remediation plan aiming to achieve compliance in the future. Capital Expenditures
Our capital expenditures primarily relate to the enhancement of our existing power plants and the exploration, development and construction of new power plants.
We have budgeted approximately$454 million in capital expenditures for construction of new projects and enhancements to our existing power plants, of which we had invested$177 million as ofDecember 31, 2020 . We expect to invest approximately$200 million in 2021 and the remaining approximately$77 million on thereafter. 100
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In addition, we estimate approximately$245 million in additional capital expenditures in 2021 to be allocated as follows: (i) approximately$150 million for the exploration and development of new projects and enhancements of existing power plants that are not yet released for full construction; (ii) approximately$40 million for maintenance of capital expenditures to our operating power plants including drilling in our Puna power plant; (iii) approximately$45 million for the construction and development of storage projects; and (iv) approximately$10.0 million for enhancements to our production facilities.
In the aggregate, we estimate our total capital expenditures for 2021 to be
approximately
Exposure to Market Risks 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. We, like other power plant operators, are exposed to electricity price volatility risk. Our exposure to such market risk is currently limited because many of our long-term PPAs (except for the 25 MW PPA for thePuna Complex and the between 30 MW and 40 MW PPAs in the aggregate for theHeber 2 power plant in theHeber Complex and the G2 power plant in theMammoth Complex ) have fixed or escalating rate provisions that limit our exposure to changes in electricity prices. Our energy storage projects sell on "merchant" and are exposed to changes in the electricity market prices.The energy payments under the PPAs of theHeber 2 power plant in theHeber Complex and the G2 power plant in theMammoth 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, 2020 , 97.2% of our consolidated long-term debt was fixed rate debt and therefore was not subject to interest rate volatility risk and 2.8% of our long-term debt was floating rate debt, exposing us to interest rate risk in connection therewith. As ofDecember 31, 2020 ,$40.8 million of our long-term debt remained subject to interest rate risk.
We currently maintain our surplus cash in short-term, interest-bearing bank
deposits, money market securities and commercial paper with a minimum investment
grade rating of AA by
Our cash equivalents are subject to interest rate risk. Fixed rate securities may have their market value adversely impacted by a rise in interest rates, while floating rate securities may produce less income than expected if interest rates fall. As a result of these factors, our future investment income may fall short of expectations because of changes in interest rates, or we may suffer losses in principal if we are forced to sell securities that decline in market value because of changes in interest rates. As ofDecember 31, 2020 , we do not hold such securities. We are also exposed to foreign currency exchange risk, in particular the fluctuation of theU.S. dollar versus the NIS inIsrael and 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 Boulliante 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/Dollar currency exposure and expect to continue to use currency exchange and other derivative instruments to the extent we deem such instruments to be the appropriate tool for managing such exposure. 101
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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, 2020 and 2019 by a hypothetical 10% and calculating the resulting change in the fair values. At this time, the development of our strategic plan has not exposed us to any additional market risk. However, as the implementation of the plan progresses, we may be exposed to additional or different market risks.
The results of the sensitivity analysis calculations as of
Assuming a 10%
Increase in Rates Assuming a 10% Decrease in Rates
As of December 31, As of December 31,
Risk 2020 2019 2020 2019 Change in the Fair Value of
(In thousands)
Foreign Currency Forward
Foreign Currency
5,131 Contracts
Interest Rate $ (3,025 ) $ (4,574 ) $ 3,090 $ 4,723 OFC 2 Senior Secured Notes
Interest Rate $ (3,193 ) $ (4,647 ) $ 3,273 $ 4,812 DFC Loan
Interest Rate $ (311 ) $ (516 ) $ 318 $ 534 Amatitlan loan
Interest Rate $ (4,278 ) $ (1,797 ) $ 4,313 $ 1,822 Senior Unsecured Bonds
Interest Rate $ (586 ) $ (905 ) $ 599 $ 934 DEG 2 Loan
Interest Rate $ (1,266 ) $ (1,835 ) $ 1,299 $ 1,906 DAC 1 Senior Secured Notes
Migdal Loan and the
Additional Migdal Loan and
the Second Addendum Migdal
Interest Rate $ (3,194 ) $ (3,272 ) $ 3,270 $ 3,363 Loan
Interest Rate $ (941 ) $ (1,141 ) $ 983 $ 1,207 San Emidio Loan
Interest Rate $ (444 ) $ (776 ) $ 450 $ 797 DOE Loan
Interest Rate $ (151 ) $ (281 ) $ 153 $ 286 Idaho Holdings Loan
Interest Rate $ (2,146 ) $ (2,978 ) $ 2,209 $ 3,099 Platanares DFC Loan
Interest Rate $ (452 ) $ (728 ) $ 461 $ 749 DEG 3 Loan
Interest Rate $ (179 ) $ (342 ) $ 181 $ 350 Plumstriker Loan
Interest Rate $ - $ (295 ) $ - $ 298 Commercial Paper
Interest Rate $ (107 ) $ (201 ) $ 108 $ 204 Other long-term loans
In July 2019 , the United Kingdom's Financial Conduct Authority , which regulates
LIBOR (London Interbank Offered Rate), announced that it intends to phase out
LIBOR by the end of 2021. It is unclear whether or not LIBOR will cease to exist
at that time and/or whether new methods of calculating LIBOR will be established
such that it will continue to exist after 2021. The U.S. Federal Reserve , in
conjunction with the Alternative Reference Rates Committee, a steering committee
comprised of large U.S. financial institutions, is considering replacing U.S.
dollar LIBOR with a new SOFR (Secured Overnight Financing Rate) index calculated
by short-term repurchase agreements, backed by Treasury securities.
We have evaluated the impact of the transition from LIBOR, and currently believe that the transition will not have a material impact on our consolidated financial statements.
Effect of Inflation
We expect that inflation will not be a significant risk in the near term, given
the current global economic conditions, however, that could change in the
future. To address the possibility of rising inflation, some of our contracts
include certain provisions that mitigate inflation risk.
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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.
Contractual Obligations and Commercial Commitments
The following tables set forth our material contractual obligations as of
Payments Due by Period
Remaining
Total 2021 2022 2023 2024 2025 Thereafter
Long-term liabilities
principal $ 1,475,853 $ 78,602 $ 337,166 $ 134,549 $ 118,395 $ 118,831 $ 688,310
Interest on long-term
liabilities (1) 381,869 71,771 66,687 46,759 44,196 38,279 114,177
Finance lease
obligations 16,723 4,177 4,116 3,015 1,156 565 3,694
Operating lease
obligations 20,320 3,255 2,539 1,902 1,625 1,440 9,559
Benefits upon retirement
(2) 20,454 4,968 1,910 148 686 1,160 11,582
Asset retirement
obligation 63,457 - - - - - 63,457
Purchase commitments (3) 159,850 159,850 - - - - -
$ 2,138,526 $ 322,623 $ 412,418 $ 186,373 $ 166,058 $ 160,275 $ 890,779 (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, 2020, total obligations related to such supplier agreements were
approximately
construction-in-process). All such obligations are payable in 2021.
The table above does not reflect unrecognized tax benefits of $2.0 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 $111.5 million , the timing of which
is uncertain and other long-term liabilities of $6.2 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.
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Table of Contents 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), KPLC and SCPPA. If any of these electric utilities fail to make payments under its PPAs with us, such failure would have a material adverse impact on our financial condition. Also, by implementing our multi-year strategic plan we may be exposed, by expanding our customer base, to different credit profile customers than our current customers. The Company's revenues from its primary customers as a percentage of total revenues are as follows: Year Ended December 31, 2020 2019 2018 Southern California Public Power Authority ("SCPPA") 20.6 17.9 15.2 Sierra Pacific Power Company and Nevada Power Company 17.5 % 16.8 % 16.1 % Kenya Power and Lighting Co. Ltd. ("KPLC") 16.4 16.3 16.6 We have historically been able to collect on substantially all of our receivable balances. As ofDecember 31, 2020 , the amount overdue from KPLC inKenya was$48.9 million of which$16.2 million was paid in January and February of 2021. These amounts are an average of 78 days overdue. InHonduras , the Company successfully collected during the year an overdue debt from Empresa Nacional de Energía Eléctrica ("ENEE") of$20.1 million that was related to the period fromOctober 2018 toApril 2019 . However, due to continuing restrictive measures related to the COVID-19 pandemic inHonduras , the Company may experience delays in collection. As ofDecember 31, 2020 , the total amount overdue from ENEE of$2.9 million was collected inJanuary 2021 . In addition, onApril 30, 2020 , the Company also received from ENEE a notice declaring a force majeure event inHonduras due to the impact of COVID-19 that was ultimately withdrawn.
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 2020 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.
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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 afterSeptember 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.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). This impact will be recorded in the first quarter of 2021. See Note 24 to our consolidated financial statements set forth in Item 8 of this annual report for further information.Kenya tax audit The Company was audited by theKenya Revenue Authority ("KRA") for income tax years 2013 to 2017 for which it had received during 2019 and 2020 three separate Notices of Assessments ("NoA") detailing different issues relating to certain findings in respect of the KRA review of such years. OnOctober 19, 2020 , the Company entered into a settlement agreement in relation to the second NoA that was issued by the KRA onDecember 4, 2019 totaling approximately$190 million of proposed adjustments, including interest and penalties. The settlement agreement extended the audit period for the issues addressed within the assessment, to cover the period from 2013 through 2019 and resulted in a total settlement payment of approximately$28 million , including interest and penalties, related to late payment in respect of 2019 taxable income. Additionally, the settlement included a deferral of tax benefits to be utilized in years subsequent to 2019 in an amount of approximately$28 million . The assessment was paid onOctober 27, 2020 . OnDecember 21, 2020 , the Company entered into a settlement agreement with the KRA in relation to the first and third NoA's that were issued by the KRA onJune 28, 2019 andMay 12, 2020 , respectively, totaling approximately$9 million , including interest and penalties. The total settlement amount reflected in the agreement was$1.5 million , which was paid onDecember 28, 2020 . This concluded all open audits and NoAs with the KRA.
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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