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 2019 Revenues
For the year ended
For the year endedDecember 31, 2019 , Electricity segment revenues were$540.3 million , compared to$509.9 million for the year endedDecember 31, 2018 , an increase of 6.0%. Product segment revenues for the year endedDecember 31, 2019 were$191.0 million , compared to$201.7 million for the year endedDecember 31, 2018 , a decrease of 5.3%. Energy Storage and Management Services segment revenues for the year endedDecember 31, 2019 were$14.7 million , compared to$7.6 million for the year endedDecember 31, 2018 .
During the years ended
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For the year endedDecember 31, 2019 , our Electricity segment generated 72.4% of our total revenues (70.9% in 2018), while our Product segment generated 25.6% of our total revenues (28.0% in 2018), and our Energy Storage and Management Services segment generated 2.0% of our total revenues (1.1% in 2018). For the year endedDecember 31, 2019 , approximately 97.6% 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. We recently signed a new PPA related to Puna with
fixed prices (see "Recent Developments" below). 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 and Management Services segment are derived primarily from BSAAS systems, demand response and energy management services and may fluctuate between period to period. Pricing of such services and products are dependent on market supply and demand trends, market volatility, the need and price for ancillary services and other factors that may change over time. 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 and Management Services 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. Recent Developments
The most significant recent developments for our company and business during 2019 and 2020 to date are described below.
• In
Officer, effective
Company, its employees and its shareholders. It is intended that
will become a member of
Chief Executive Officer and will continue to be employed by the Company
through
and Chief Financial Officer, to succeed
the role of Chief Executive Officer on
retirement.
Ginzburg, effective
President of the Company until assuming his role as Chief Executive Officer on
Chief Financial Officer of Delek US Holdings, Inc. (NYSE: DK) and Delek
energy industry. In his financial positions,
senior financial professionals and has significant experience in all aspects
of corporate finance, financial planning, tax, accounting and investor relations.
• As of
permits that are required for the construction and operation of the substation
were delayed and were received in mid
efforts to complete the upgrade of the transmission network. On the field
side, we completed the drilling of one production well that was blocked
immediately after flow test of the well. We continue our field recovery work,
which includes redrilling of existing wells, cleanouts and drilling of new
wells and we expect initial power generation for testing during the second
quarter of 2020. Commercial operation of the full generating capacity of the
Puna power plant is expected in the third quarter assuming all permits are
received, transmission network upgrade is complete and field recovery is
successfully achieved. 77
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• In
(SVCE) and
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 Southern
power plant is expected to be on-line by the end of 2021, will be the first
geothermal power plant built within the
(CAISO) balancing authority in the last 30 years and will be the first in
• In
reached an agreement on an amended and restated PPA for dispatchable
geothermal power sold from
capacity of 46MW and a fixed price with no escalation, regardless of changes
to fossil fuel pricing. The energy rate under the contract is fixed at
per MWh for all energy purchased during any contract year up to 227,000 MWh
and
the contract are approximately
the
approval, which is anticipated during 2020. We are planning to replace ten
25-year-old steam units with two new
existing auxiliary equipment. This upgraded facility will utilize the same
amount of geothermal resource that the existing 38 MW facility requires. The
COD of the new plant is expected during the first half of 2022. The existing
PPA remains in effect, with current terms, until the expansion is completed,
and the new plant reaches its COD. • InDecember 2019 , the tax extenders package was signed into law and
retroactively revived and extended the full PTC for geothermal facilities. The
PTC rules provide a tax credit for each kWh of electricity produced by the
taxpayer from qualified renewable energy facilities. The PTC for geothermal
facilities that expired at the end of 2017 was retroactively revived and
extended through 2020, continuing
This extension will drive and enhance our development of geothermal projects.
This support contributes to the ongoing creation of new jobs in the geothermal
industry as well as to the nation's energy independence.
• In
to serve as our President, effective immediately. As President,
assists our CEO,
operational management until he assumes
• In
indirectly owns the 48MW McGinness Hills Phase 3 geothermal power plant
entered into a partnership agreement with a private investor. Pursuant to the
transaction agreement, the private investor acquired membership interests in
the project for an initial purchase price of approximately
for which it will pay additional annual installments that are expected to
amount to a total of approximately
based on the actual generation. We will continue to consolidate, operate and
maintain the power plant and will receive substantially all of the
distributable cash flow generated by the power plant, and prior to December
2027 the private investor will receive substantially all of the tax attributes.
• In
and solar hybrid project, a 7MW AC solar expansion of our
geothermal project in
the Tungsten solar power plant will be used to offset the equipment's energy
use at the Tungsten geothermal facility, thus increasing the renewable energy
delivered by the project under the
("SCPPA") portfolio contract. SCPPA and the
and Power had the vision to enable this development through their innovative
portfolio contract, which sought to maximize the output of their renewable
facilities and furthering the transition away from coal power while maintaining a reliable power supply forLos Angeles . 78
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• In
acquire 49% of the Ijen geothermal project company, which is holding a PPA and
geothermal license to develop the Ijen project in
a
49% of the shares of the Ijen geothermal project company and committed to make
additional funding for the project exploration and development, subject to
specific conditions. A subsidiary of
company.
The Ijen project assets, whose final capacity will be determined after
exploration, include a geothermal concession and 30-year PPA for up to 110 MW
capacity. The project is ready for exploration and development with some slim
holes already drilled.
• In
loan agreement with
and Stryker, two 20 MW battery energy storage projects located in
The loan bears interest of three months
final maturity date isMay 30, 2026 .
• In
Migdal Loan Agreement with several entities within the
Israeli insurance company and institutional investor in
Addendum provides us with an additional loan by the lenders in an aggregate
principal amount of
payments of
payment of
interest at a fixed rate of 4.6% per annum, payable semi-annually. • InMarch 2019 , we announced the signing of a PPA between one of our
subsidiaries and SCPPA. Under the PPA, SCPPA will purchase 16MW of power
generated by the expected 30MW Casa Diablo-IV ("CD4") geothermal project
located in
of
within the
authority in the last 30 years. The 16MW of energy deliveries under the PPA
will begin no later than the end of 2021 with an extension option. The PPA is
for a term of 25 years and has a fixed price of
negotiations to sell the balance of 14MW to other offtakers or at the spot
market.
• In
with Deutsche Investitions-und Entwicklungsgesellschaft mbH ("DEG") and on
fixed interest rate of 6.04% for the duration of the loan. The loan is being
repaid in 19 equal semi-annual principal installments, which commenced on June
21, 2019, with a final maturity date of
were used to refinance upgrades to Plant 1 of theOlkaria III Complex . 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 accelerated our efforts to expand business development activities in
developing countries where geothermal is considered a local resource that can
provide a stable and cost effective solution to increase access to power. 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. 79
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? In the Electricity segment, we expect intense domestic competition from the
solar 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 leads to further
reductions in the prices that we are able to charge for our binary equipment,
as we recently experienced in
We are experiencing such competition in other locations where we operate which
may have an adverse impact on the prices we can charge and our profitability.
? 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 total Electricity segment, we earned, on average,
in 2019 and 2018, 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. ?Turkey's geothermal market is one of the fastest growing markets in the
geothermal industry worldwide, mainly due to governmental and regulatory
support.
capacity of over 1,600 MW. Our revenue exposure to the Turkish market remained
significant in 2019 and expects to reduce in 2020, due to slowdown in project
development in the Turkish market. The continued deterioration in the Turkish
economy, devaluation in the Turkish Lira and increase in local interest rates
or a decline in government support for the development of geothermal 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 addition, the impact of threatened or
actual
diplomatic relations may harm regional demand or price 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
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 customer for 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.
? In
from the KRA in relation to its review of the 2013 to 2017 tax years in which
the KRA demanded we pay approximately
penalties (
discussions with the KRA on the matters included in their letters of
assessment and preliminary findings and believe our tax positions for the
issues raised during the audit are sustainable based on the technical merits
under Kenyan tax law. See further details under our Item 8 below.
? While the recently enacted Tax Act reduces the corporate tax rate, it is
also expected to increase the cost of capital for renewable energy projects.
Such projects often rely on "tax equity" as a core financing tool. Tax equity
is a form of financing that is repaid partly or wholly in tax benefits and
sometimes partly in cash. There are two types of federal income tax benefits
on renewable energy projects: a tax credit and depreciation, or the ability to
deduct the cost of the project. The reduction in the corporate tax rate from
35 percent to 21 percent reduces the value of the depreciation. Therefore,
less tax equity can be raised on projects. The gap in the capital structure
must be filled with debt and/or more expensive sponsor equity. The Tax Act
allowed the full cost of equipment placed in service between
2017 and
market is not expected to take advantage of this tax benefit and, because of
the way tax equity works, we have had to take depreciation on a straight-line
basis over 12 years rather than on a front-loaded basis over five years in
some tax equity transactions, which leads to some further erosion in the
present value of the depreciation. Other effects of the Tax Act are discussed
later under Note 18 - Income Taxes to our consolidated financial statements.
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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; the sale of energy storage services from our operating facilities and the sale of BSAAS systems and demand response and energy management services. Revenues attributable to our Electricity segment are derived from the sale of electricity from our power plants pursuant to long-term PPAs. While approximately 97.6% of our Electricity revenues for the year endedDecember 31, 2019 were derived from PPAs with fixed price components, we have 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 and Management Services segment are derived primarily from BSAAS systems, demand response and energy management services and may fluctuate period to period.
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BSAAS are battery storage deals that are financed, owned and operated by us. BSAAS revenues are a combination of sales of the electricity back to the utilities and energy markets based on the prevailing market price for the electricity or for the energy or ancillary services. The energy and ancillary services revenue includes frequency regulation, standby capacity, synchronized reserve, reactive power and other related services. Additionally, when providing a "behind the customer meter solution" we also generate revenue from sharing savings generated from reducing the customer's utility bill. We also act as a general contractor on turnkey BESS for customers. BESS systems are owned by the customer and we provide the EPC for the project, delivering to the customer a fully operational system. Along with the BESS we also provide the management and operation of the battery for the customer for the life of the system which is typically 10 to 20 years. The EPC portion of the turnkey BESS revenue is a one-time charge and usually will be based on mile-stones or upon delivery. Revenues attributable to our demand response and energy management services are derived by two methods. The first method is a fixed monthly or annual recurring fee for managing the customer's energy assets and monetizing them in either the energy markets or through reducing the customer's charges from their utility. The second method is through sharing the revenues or savings generated from monetizing their flexible electricity in the energy markets (revenue) or through reducing the customer's bill from the utility (savings). The second method is subject to energy price fluctuations and the available flexible electricity. Revenues attributable to our Software as a Service are based on a fixed monthly or annual fee for energy management information and analytical services. Contract periods are typically 12 months or more. To date, we have experienced minimal customer churn. The following table sets forth a breakdown of our revenues for the years indicated: Revenues (dollars in thousands) %
of Revenues for Period Indicated
Year EndedDecember 31 ,
Year Ended
2019 2018 2017 2019 2018 2017 Revenues: Electricity$ 540,333 $ 509,879 $ 465,593 72.4 % 70.9 % 67.2 % Product 191,009 201,743 224,483 25.6 28.0 32.4 Energy Storage and Management Services 14,702 7,645 2,736 2.0 1.1 0.4 Total revenues$ 746,044 $ 719,267 $ 692,812 100.0 % 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 and Management Services segments for the years indicated:
Revenues in Thousands % of
Revenues for Period Indicated
Year EndedDecember 31 ,
Year Ended
2019 2018 2017 2019 2018 2017 Electricity Segment: United States$ 333,797 $ 305,962 $ 295,484 61.8 % 60.0 % 63.5 % International 206,536 203,917 170,109 38.2 40.0 36.5 Total$ 540,333 $ 509,879 $ 465,593 100.0 % 100.0 % 100.0 % Product Segment: United States$ 30,562 $ 14,999 $ 2,912 16.0 % 7.4 % 1.3 % International 160,447 186,744 221,571 84.0 92.6 98.7 Total$ 191,009 $ 201,743 $ 224,483 100.0 % 100.0 % 100.0 % Energy Storage and Management Services Segment: United States$ 13,597 $ 7,645 $ 2,736 92.5 % 100.0 % 100.0 % International 1,105 - - 7.5 0.0 0.0 Total$ 14,702 $ 7,645 $ 2,736 100.0 % 100.0 % 100.0 % 82
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In 2019, 2018 and 2017, 49%, 54% and 57% of our revenues were derived from international operations, respectively, and our international operations were more profitable than ourU.S. operations in each of those years. A substantial portion of international revenues came fromKenya andTurkey and, to a lesser extent, fromHonduras ,Guadeloupe ,Guatemala and other countries. Our operations inKenya 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 62%, 60% and 64% of our total Electricity segment for the years endedDecember 31, 2019 , 2018 and 2017, 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, likeKenya ,Guatemala ,Honduras andGuadeloupe , 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 2019 the international operations of the segment accounted for 52% of our total gross profits, 59% of our net income and 48% of our EBITDA. Product Segment. Our Product segment foreign revenues were 84%, 93% and 99% of our total Product segment revenues for the years endedDecember 31, 2019 , 2018 and 2017, 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 in the winter months to be higher than the revenues 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 4.1% and 4.2% of Electricity segment revenues for the years endedDecember 31, 2019 and 2018, respectively. 83
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Table of Contents 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 and Management Services Segment
The principal cost of revenues attributable to our Energy Storage and Management Services segment are direct costs attributable to providing services and equipment to our customers, direct costs associated with software development and the direct cost of operating batteries that are owned by Viridity. Direct costs include labor costs of our network operations center, the labor costs for engineering and implementation of services to customers, consulting services provided to customers and developing software and the labor associated with operations and maintenance for customer and our Viridity owned energy assets. Cost of revenues attributable to our Energy Storage and Management Services segment also include cost of equipment sold to customers in delivering our automated demand response and software services at a customer's location, the cost of batteries or other associated equipment that is sold to customers and for any third party related costs such as local construction, local engineering or other similar costs incurred in implementing and managing the customers' energy assets.
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 a
result, we review and update our cost estimates on significant contracts on a
quarterly basis, and at least on an annual basis for all others, or when
circumstances change and warrant a modification to a previous estimate.
Changes in job performance, job conditions, and estimated profitability,
including those arising from the application of penalty provisions in relevant
contracts and final contract settlements, may result in revisions to costs and
revenues and are recognized in the period in which the revisions are
determined. Provisions for estimated losses relating to contracts are made in
the period in which such losses are determined. Revenues generated from engineering and operating services and sales of products and parts are recorded once the service is provided or product delivery is made, as applicable. 84
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• Property, Plant and Equipment. We capitalize all costs associated with the
acquisition, development and construction of power plant facilities. Major
improvements are capitalized and repairs and maintenance (including major
maintenance) costs are expensed. We estimate the useful life of our power
plants to range between 25 and 30 years. Such estimates are made by management
based on factors such as prior operations, the terms of the underlying PPAs,
geothermal resources, the location of the assets and specific power plant
characteristics and designs. Changes in such estimates could result in useful
lives which are either longer or shorter than the depreciable lives of such
assets. We periodically re-evaluate the estimated useful life of our power
plants and revise the remaining depreciable life on a prospective basis.
We capitalize costs incurred in connection with the exploration and development of geothermal resources beginning when we acquire land rights to the potential geothermal resource. Prior to acquiring land rights, we make an initial assessment that an economically feasible geothermal reservoir is probable on that land using available data and external assessments vetted through our exploration department and occasionally outside service providers. Costs incurred prior to acquiring land rights are expensed. It normally takes two to three years from the time we start active exploration of a particular geothermal resource to the time we have an operating production well, assuming we conclude the resource is commercially viable. In most cases, we obtain the right to conduct our geothermal development and operations on land owned by the BLM, various states or with private parties. 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$84.6 million and$71.0 million atDecember 31, 2019 and 2018, respectively. Included in these amounts atDecember 31, 2019 and 2018, respectively, are$17.0 million and$17.0 million , respectively, which relate to up-front bonus payments.
• 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 management combined operation generally with one central control room that controls 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 endedDecember 31, 2019 , 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. 85
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•
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
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
FASB issued ASU 2017-04, Intangibles -
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 reporting unit's goodwill with the carrying amount
of that goodwill. Under ASU 2017-04, Intangibles -
entity should recognize an impairment charge for the amount by which the
carrying amount of the reporting unit exceeds its fair value as calculated
under step one described above. However, the loss recognized should not exceed
the total amount of goodwill allocated to that reporting unit
• Obligations Associated with the Retirement of Long-Lived Assets. We record the
fair market value of legal liabilities related to the retirement of our assets
in the period in which such liabilities are incurred. These liabilities
include our obligation to plug wells upon termination of our operating
activities, the dismantling of our power plants upon cessation of our
operations, and the performance of certain remedial measures related to the
land on which such operations were conducted. When a new liability for an
asset retirement obligation is recorded, we capitalize the costs of such
liability by increasing the carrying amount of the related long-lived asset.
Such liability is accreted to its present value each period and the
capitalized cost is depreciated over the useful life of the related asset. At
retirement, we either settle the obligation for its recorded amount or report
either a gain or a loss with respect thereto. Estimates of the costs
associated with asset retirement obligations are based on factors such as
prior operations, the location of the assets and specific power plant
characteristics. We review and update our cost estimates periodically and
adjust our asset retirement obligations in the period in which the revisions
are determined. If actual results are not consistent with our assumptions used
in estimating our asset retirement obligations, we may incur additional losses
that could be material to our financial condition or results of operations.
• Accounting for Income Taxes. Significant estimates are required to arrive at
our consolidated income tax provision. This process requires us to estimate
our actual current tax exposure and to make an assessment of temporary
differences resulting from 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 the valuation allowance. In assessing the need for a valuation allowance, we estimate future taxable income, including the impacts of the passing of the Tax Act, considering the feasibility of ongoing tax planning strategies and the realization 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 ourU.S. deferred tax assets. In the future, if there is sufficient evidence that we will be able to generate sufficient future taxable income inthe United States , we may be required to further reduce this valuation allowance, resulting in income tax benefits in our consolidated statement of operations. In the ordinary course of business, there is 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 these uncertainties in a manner inconsistent with our expectations could have a material impact on our financial condition or results of operations. 86
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New Accounting Pronouncements
See Note 1 to our consolidated financial statements set forth in Item 8 of this annual report for information regarding new accounting pronouncements.
Results of Operations
Our historical operating results in dollars and as a percentage of total revenues are presented below.
Year Ended December 31, 2019 2018 2017 (Dollars in thousands, except per share data) Revenues: Electricity$ 540,333 $ 509,879 $ 465,593 Product 191,009 201,743 224,483 Energy storage and management services 14,702 7,645 2,736 Total revenues 746,044 719,267 692,812 Cost of revenues: Electricity 312,835 298,255 266,840 Product 145,974 140,697 152,094 Energy storage and management services 17,912 9,880 5,426 Total cost of revenues 476,721 448,832 424,360 Gross profit (loss) Electricity 227,498 211,624 198,753 Product 45,035 61,046 72,389 Energy storage and management services (3,210 ) (2,235 ) (2,690 ) Total gross profit 269,323 270,435 268,452 Operating expenses: Research and development expenses 4,647 4,183 3,157 Selling and marketing expenses 15,047 19,802 15,600 General and administrative expenses 55,833 47,750 42,881 Impairment charge - 13,464 - Write-off of unsuccessful exploration activities - 126 1,796 Operating income 193,796 185,110 205,018 Other income (expense): Interest income 1,515 974 988 Interest expense, net (80,384 ) (70,924 ) (54,142 ) Derivatives and foreign currency transaction gains (losses) 624 (4,761 ) 2,654 Income attributable to sale of tax benefits 20,872 19,003 17,878 Other non-operating income (expense), net 880 7,779 (1,666 ) Income from operations before income tax and equity in earnings (losses) of investees 137,303 137,181 170,730 Income tax (provision) benefit (45,613 ) (34,733 ) (21,664 ) Equity in earnings (losses) of investees, net 1,853 7,663 (1,957 ) Net Income 93,543 110,111 147,109 Net income attributable to noncontrolling interest (5,448 ) (12,145 ) (14,695 ) Net income attributable to the Company's stockholders$ 88,095 $ 97,966 $ 132,414 Earnings per share attributable to the Company's stockholders: Basic: Net income $ 1.73 $ 1.93$ 2.64 Diluted: Net income $ 1.72 $ 1.92$ 2.61 Weighted average number of shares used in computation of earnings per share attributable to the Company's stockholders: Basic 50,867 50,643 50,110 Diluted 51,227 50,969 50,769 87
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Results as a percentage of revenues
Year Ended December 31, 2019 2018 2017 Revenues: Electricity 72.4 % 70.9 % 67.2 % Product 25.6 28.0 32.4 Energy storage and management services 2.0 1.1 0.4 Total revenues 100.0 100.0 100.0 Cost of revenues: Electricity 57.9 58.5 57.3 Product 76.4 69.7 67.8 Energy storage and management services 121.8 129.2 198.3 Total cost of revenues 63.9 62.4 61.3 Gross profit (loss) Electricity 42.1 41.5 42.7 Product 23.6 30.3 32.2 Energy storage and management services (21.8 ) (29.2 ) (98.3 ) Total gross profit 36.1 37.6 38.7 Operating expenses: Research and development expenses 0.6 0.6 0.5 Selling and marketing expenses 2.0 2.8 2.3 General and administrative expenses 7.5 6.6 6.2 Impairment charge 0.0 1.9 0.0 Write-off of unsuccessful exploration activities 0.0 0.0 0.3 Operating income 26.0 25.7 29.6 Other income (expense): Interest income 0.2 0.1 0.1 Interest expense, net (10.8 ) (9.9 ) (7.8 ) Derivatives and foreign currency transaction gains (losses) 0.1 (0.7 ) 0.4 Income attributable to sale of tax benefits 2.8 2.6 2.6 Other non-operating income (expense), net 0.1 1.1 (0.2 ) Income from continuing operations before income tax and equity in earnings (losses) of investees 18.4 19.1 24.6 Income tax (provision) benefit (6.1 ) (4.8 ) (3.1 ) Equity in earnings (losses) of investees, net 0.2 1.1 (0.3 ) Net Income 12.5 15.3 21.2 Net income attributable to noncontrolling interest (0.7 ) (1.7 ) (2.1 ) Net income attributable to the Company's stockholders 11.8 % 13.6 % 19.1 % 88
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Comparison of the Year Ended
Total Revenues (Dollars in millions)
Year Ended Year Ended December 31, December 31, 2019 2018 Change (Dollars in millions) Electricity segment revenues$ 540.3 $ 509.9 6 % Product segment revenues 191.0 201.7 (5 )% Energy Storage and Management Services segment revenues 14.7 7.6 92 % Total Revenues$ 746.0 $ 719.3 4 % Electricity Segment Revenues attributable to our Electricity segment for the year endedDecember 31, 2019 were$540.3 million , compared to$509.9 million for the year endedDecember 31, 2018 , representing a 6.0% increase from the prior period. This increase was primarily attributable to: (i) the commencement of commercial operation of the third phase of ourMcGinness Hills Complex inNevada , effectiveDecember 2018 , which generated total complex revenues of$96.9 million for the year endedDecember 31, 2019 compared to$65.1 million for the year endedDecember 31, 2018 ; (ii) the consolidation of USG which was acquired onApril 24, 2018 , and contributed$35.6 million for the year endedDecember 31, 2019 , compared to$21.4 million for the year endedDecember 31, 2018 ; and (iii) the commencement of commercial operation of our Plant 1 expansion project in theOlkaria III Complex inKenya , effectiveJune 2018 . The increase was partially offset by (i) the shutdown of our Puna power plant following theKilauea volcanic eruption onMay 3, 2018 which resulted in a reduction of$15.5 million in revenues compared to the year endedDecember 31, 2018 ; and (ii) a decrease in generation at some of our other power plants that were taken offline to address maintenance issues in the ordinary course of business as well as curtailments by the offtaker in the Olkaria complex. Power generation in our power plants increased by 6.5% from 5,857,963 MWh in the year endedDecember 31, 2018 to 6,238,272 MWh in the year endedDecember 31, 2019 , primarily because of an increase in generation due to the commencement of commercial operation of the third phase of ourMcGinness Hills Complex inNevada , Plant 1 expansion inKenya and the acquisition of USG. The increase was partially offset by (i) the shutdown of our Puna power plant following the Kilauea Volcanic Eruption and (ii) lower generation at some of our other power plants mainly due to higher ambient temperature and maintenance issues in the ordinary course of business as well as curtailments by the offtaker in the Olkaria III complex. Product Segment Revenues attributable to our Product segment for the year endedDecember 31, 2019 were$191.0 million , compared to$201.7 million for the year endedDecember 31, 2018 , representing a 5.3% decrease from the prior period. The decrease in our Product segment revenues was mainly due to projects that were completed inTurkey in 2018, which accounted for$91.1 in Product segment revenues in the year endedDecember 31, 2018 , which were partially offset by (i) the start of four new projects inTurkey ,New Zealand andChile in 2019, which provided$90.3 million in revenue for the year endedDecember 31, 2019 ; and (ii) other projects mainly inTurkey and theU.S. , which were started in 2018, and provided$72.2 million in revenue for the year endedDecember 31, 2019 compared to$90.0 million for the year endedDecember 31, 2018 . 89
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Energy Storage and Management Services Segment
Revenues attributable to our Energy Storage and Management Services segment for the year endedDecember 31, 2019 were$14.7 million compared to$7.6 million for the year endedDecember 31, 2018 . The increase was mainly driven by the start of operation of two energy storage facilities in the PJM market. The Energy Storage and Management Services segment includes revenues from the delivery of energy storage demand response and energy management services.
Total Cost of Revenues (Dollars in millions)
Year Ended Year Ended December 31, December 31, 2019 2018 Change (Dollars in millions) Electricity segment cost of revenues$ 312.8 $ 298.3 4.9 % Product segment cost of revenues 146.0 140.7 3.8 % Energy Storage and Management Services segment cost of revenues 17.9 9.9 81.3 % Total Cost of Revenues$ 476.7 $ 448.8 6.2 % Electricity Segment Total cost of revenues attributable to our Electricity segment for the year endedDecember 31, 2019 was$312.8 million , compared to$298.3 million for the year endedDecember 31, 2018 , representing a 4.9% increase from the prior period. This increase was primarily attributable to: (i) additional cost of revenues from the commencement of commercial operation of the third phase of ourMcGinness Hills Complex plant inNevada , effectiveDecember 2018 and (ii) commencement of commercial operation of our Plant 1 expansion project in theOlkaria III Complex inKenya , effectiveJune 2018 . As a percentage of total Electricity revenues, the total cost of revenues attributable to our Electricity segment for the year endedDecember 31, 2019 was 57.9%, compared to 58.5% for the year endedDecember 31, 2018 . This decrease was primarily attributable to an increase in gross profit due to the commencement of commercial operation of the third phase of ourMcGinness Hills Complex and from our assets that were acquired from USG and contributed partially in 2018, partly offset by the Puna power plant inHawaii , for which we recorded cost of revenues with no associated revenues due to the shut-down of the power plant following theKilauea volcanic eruption inMay 3, 2018 . The cost of revenues attributable to our international power plants was 23.6% of our Electricity segment cost of revenues. Product Segment Total cost of revenues attributable to our Product segment for the year endedDecember 31, 2019 was$146.0 million , compared to$140.7 million for the year endedDecember 31, 2018 , representing a 3.8% increase from the prior period. This increase was primarily attributable to higher competition, different product scope and different margins in the various sales contracts we entered into for the Product segment during these periods, specifically related to two large but lower margin contracts inTurkey that had an impact on revenue and related cost of revenues in the year endedDecember 31, 2019 . As a percentage of total Product segment revenues, our total cost of revenues attributable to our Product segment for the year endedDecember 31, 2019 was 76.4%, compared to 69.7% for the year endedDecember 31, 2018 .
Energy Storage and Management Services Segment
Cost of revenues attributable to our Energy Storage and Management Services segment for the year endedDecember 31, 2019 were$17.9 million as compared to$9.9 million in the year endedDecember 31, 2018 . The increase was mainly driven by the start of operation of two storage energy facilities in the PJM market. The Energy Storage and Management Services segment includes cost of revenues related to the delivery of energy storage, demand response and energy management services.
Research and Development Expenses
Research and development expenses for the year ended
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Selling and Marketing Expenses
Selling and marketing expenses for the year endedDecember 31, 2019 were$15.0 million , compared to$19.8 million for the year endedDecember 31, 2018 . This decrease was primarily due to the$5.0 million termination fee paid to NV Energy related to the termination of the Galena 2 PPA in the year endedDecember 31, 2018 . Selling and marketing expenses constituted 2.0% of total revenues for the year endedDecember 31, 2019 , compared to 2.1%, excluding the termination fee, for the year endedDecember 31, 2018 .
General and Administrative Expenses
General and administrative expenses for the year endedDecember 31, 2019 were$55.8 million , compared to$47.8 million for the year endedDecember 31, 2018 . The increase was primarily attributable to a$10.3 million income adjustment in the year endedDecember 31, 2018 , in respect of an earn out related to the acquisition of our Viridity business, partially offset by (i) higher expenses in the year endedDecember 31, 2018 related to our identification of a material weakness related to taxes in the fourth quarter of 2017 and the restatement of 2017 financial statements; (ii) costs related to the acquisition of USG in 2018; and (iii) a decrease in professional fees. General and administrative expenses for the year endedDecember 31, 2019 constituted 7.5% of total revenues for such period, compared to 8.1%, excluding the earn out adjustment, for the year endedDecember 31, 2018 . Goodwill Impairment Charge
There was no goodwill impairment charge for the year ended
Operating Income Operating income for the year endedDecember 31, 2019 was$193.8 million , compared to$185.1 million for the year endedDecember 31, 2018 , representing a 4.7% increase from the prior period. Operating income attributable to our Electricity segment for the year endedDecember 31, 2019 was$177.2 million compared to$155.5 million for the year endedDecember 31, 2018 . Operating income attributable to our Product segment for the year endedDecember 31, 2019 was$23.2 million , compared to$38.1 million for the year endedDecember 31, 2018 . Operating loss attributable to our Energy Storage and Management Services segment for the year endedDecember 31, 2019 was$6.6 million compared to$8.5 million for the year endedDecember 31, 2018 . Interest Expense, Net Interest expense, net, for the year endedDecember 31, 2019 was$80.4 million , compared to$70.9 million for the year endedDecember 31, 2018 , representing a 13.3% increase from the prior period. This increase was primarily due to (i)$100.0 million and$50.0 million of proceeds from a senior unsecured loan received onMarch 22, 2018 andMarch 25, 2019 , respectively; (ii)$96.0 million debt as part of the acquisition of USG; (iii)$114.7 million of proceeds from a limited recourse loan received onOctober 29, 2018 from OPIC for financing theHonduras power plant; and (iv)$41.5 million of proceeds from a full recourse loan received onJanuary 4, 2019 from DEG for financing theKenya power plant, partially offset due to lower interest expense as a result of principal payments of long term debt.
Derivatives and Foreign Currency Transaction Gains (Losses)
Derivatives and foreign currency transaction gains for the year endedDecember 31, 2019 were$0.6 million , compared to losses of$4.8 million for the year endedDecember 31, 2018 . Derivatives and foreign currency transaction gains for the year endedDecember 31, 2019 were attributable primarily to gains from foreign currency forward contracts, which were not accounted for as hedge transactions. Derivatives and foreign currency transaction losses for the year endedDecember 31, 2018 were primarily attributable to losses from foreign currency forward contracts, which were not accounted for as hedge transactions. 91
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Income Attributable to Sale of Tax Benefits
Income attributable to the sale of tax benefits for the year endedDecember 31, 2019 was$20.9 million , compared to$19.0 million for the year endedDecember 31, 2018 . 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, 2019 was$0.9 million , compared to other non-operating expense, net of$7.8 million for the year endedDecember 31, 2018 . Other non-operating income for the year endedDecember 31, 2019 mainly includes an 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. Other non-operating income for the year endedDecember 31, 2018 mainly includes income of a$7.2 million insurance settlement of our Puna power plant rig which was damaged by theKilauea volcanic eruption.
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, 2019 was$137.3 million , compared to$137.2 million for the year endedDecember 31, 2018 , representing an 0.1% increase from the prior period. The income is primarily attributable to our foreign operations. Income Taxes Income tax provision for the year endedDecember 31, 2019 , was$45.6 million , an increase of$10.9 million compared to an income tax provision of$34.7 million for the year endedDecember 31, 2018 . Our effective tax rate for the year endedDecember 31, 2019 and 2018, was 33.2% and 25.3%, respectively. Our effective tax rate is primarily based upon the composition of our income in different countries and changes related to valuation allowances inthe United States . Our aggregate effective tax rate for the year endedDecember 31, 2019 differs from the 21%U.S. federal statutory tax rate primarily due to the impact of global intangible low tax income (GILTI) and the mix of business in various countries with higher and lower statutory rates than the federal rate, partially offset by the generation of additional foreign tax credits through amended tax returns of prior periods. OnDecember 22, 2017 , theU.S. government signed into law the Tax Act. The Tax Act makes significant changes to theU.S. tax code, including, but not limited to, (1) reducing theU.S. federal corporate income tax rate from 35 percent to 21 percent; (2) the transition ofU.S. international taxation from a worldwide tax system to a territorial system (GILTI, BEAT, Dividends Received Deduction); (3) one-time transition tax on undistributed earnings of foreign subsidiaries as ofDecember 31, 2017 ; (4) eliminating the corporate alternative minimum tax (5) creating a new limitation on deductible interest expense; and (6) changing rules related to uses and limitations of net operating loss carryforwards created in tax years beginning afterDecember 31, 2017 .
Equity in Earnings (losses) of investees, net
Equity in earnings (losses) of investees, net in the year endedDecember 31, 2019 was$1.9 million , compared to$7.7 million in the year endedDecember 31, 2018 . Equity in earnings of investees, net is primarily derived from our 12.75% share in the earnings or losses in the Sarulla complex. The decrease was mainly attributable to a decrease in gross margin due to well-field issues in the NIL power plant which resulted in lower generation. 92
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Table of Contents Net Income Net income for the year endedDecember 31, 2019 was$93.5 million , compared to$110.1 million for the year endedDecember 31, 2018 , representing a decrease of$16.6 million from the prior period. This decrease in net income was primarily attributable to an increase in income tax provision of$10.9 million , an increase of$9.5 million in interest expense, net, a decrease of$6.9 million in other non-operating income, and a decrease of$5.8 million in equity in earnings of investees, net, partially offset by an increase of$8.7 million in operating income and an increase of$5.4 million in derivatives and foreign currency transaction gains, as discussed above.
Net Income attributable to the Company's Stockholders
Net income attributable to the Company's stockholders for the year endedDecember 31, 2019 was$88.1 million , compared to$98.0 million for the year endedDecember 31, 2018 , which represents a decrease of$9.9 million . This decrease was attributable to the decrease in net income of$16.6 million , offset partially by a decrease of$6.7 million in net income attributable to noncontrolling interest mainly due to the shutdown of the Puna power plant inHawaii , all as discussed above.
Comparison of the year ended
Total Revenues Total revenues for the year endedDecember 31, 2018 were$719.3 million , compared to$692.8 million for the year endedDecember 31, 2017 , representing a 3.8% increase from the prior period. This increase was attributable to our Electricity segment, in which revenues increased by$44.3 million or 9.5% compared to the corresponding period in 2017 and our Energy Storage and Management Services segment in which revenues increased by$4.9 million or 179.4%, as a result of revenues generated by our Viridity business from the delivery of energy storage, demand response and energy management services. This increase was partially offset by a decrease of$22.7 million , or 10.1% in our Product segment revenues compared to the corresponding period in 2017. Electricity Segment Revenues attributable to our Electricity segment for the year endedDecember 31, 2018 , were$509.9 million , compared to$465.6 million for the year endedDecember 31, 2017 , representing a 9.5% increase from the prior period. This increase was primarily attributable to: (i) the commencement of commercial operation of our Platanares power plant inHonduras , effectiveSeptember 2017 , with revenues of$34.4 million for the year endedDecember 31, 2018 compared to$10.0 million for the year endedDecember 31, 2017 ; (ii) the consolidation of USG which was acquired onApril 24, 2018 , with revenues of$21.4 million for the year endedDecember 31, 2018 ; (iii) the commencement of commercial operation of ourTungsten Mountain power plant inNevada , effectiveDecember 2017 , with revenues of$15.7 million for the year endedDecember 31, 2018 compared to$2.2 million for the year endedDecember 31, 2017 ; (iv) the commencement of commercial operation of our Plant 1 expansion project in theOlkaria III Complex inKenya , effectiveJune 2018 ; and (v) higher energy rates under the new Ormesa 1 PPA commencing inDecember 2017 . The increase was partially offset due to (i) a decrease in revenues at our Puna power plant that was shut down immediately following theKilauea volcanic eruption onMay 3, 2018 and (ii) a decrease in generation at some of our other power plants that were taken offline to address maintenance issues and enhancements, high ambient temperature and curtailments. Power generation in our power plants increased by 6.7% from 5,489,234 MWh in the year endedDecember 31, 2017 to 5,857,963 MWh in the year endedDecember 31, 2018 , primarily because of an increase in generation due to the commencement of commercial operations of our Platanares power plant inHonduras ,Tungsten Mountain power plant inNevada , and Plant 1 expansion inKenya and due to the acquisition of USG. The increase was partially offset by a decrease in generation at (i) our Puna power plant due to the Kilauea Volcanic Eruption and (ii) some of our other power plants mainly due to maintenance issues and high ambient temperature. 93
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Table of Contents Product Segment Revenues attributable to our Product segment for the year endedDecember 31, 2018 were$201.7 million , compared to$224.5 million for the year endedDecember 31, 2017 , representing a 10.1% decrease from the prior period. We recognized approximately$31.4 million and$23.1 million in revenues, from theNew Zealand andChina projects, respectively, in the year endedDecember 31, 2017 , compared to$8.8 million and$0.5 million in the year endedDecember 31, 2018 . The projects were completed in 2018. The decrease in our Product segment revenues was also attributable to other projects inTurkey , which were completed in 2017, and by a decrease in revenues as a result of completion of our contracts for geothermal projects inChile and the Sarulla project. The decrease was partially offset by the start of new projects inTurkey , which provided$154.3 million in revenue recognized during the year endedDecember 31, 2018 .
Energy Storage and Management Services Segment
Revenues attributable to our Energy Storage and Management Services segment for the year endedDecember 31, 2018 were$7.6 million compared to$2.7 million for the year endedDecember 31, 2017 . The Energy Storage and Management Services segment includes revenues from the delivery of energy storage demand response and energy management services by our Viridity business following the acquisition of substantially all of the business and assets ofViridity Energy, Inc. onMarch 15, 2017 . Total Cost of Revenues Total cost of revenues for the year endedDecember 31, 2018 was$448.8 million , compared to$424.4 million for the year endedDecember 31, 2017 , representing a 5.8% increase from the prior period. This increase was attributable to an increase of$31.4 million , or 11.8%, in cost of revenues from our Electricity segment and an increase of$4.5 million , or 82.1% from our Energy Storage and Management Services segment generated by our Viridity business. This increase was partially offset by a 7.5% decrease in our Product segment cost of revenues compared to the corresponding period in 2017. As a percentage of total revenues, our total cost of revenues for the year endedDecember 31, 2018 increased to 62.4%, compared to 61.3% for the year endedDecember 31, 2017 . Electricity Segment Total cost of revenues attributable to our Electricity segment for the year endedDecember 31, 2018 was$298.3 million , compared to$266.8 million for the year endedDecember 31, 2017 , representing a 11.8% increase from the prior period. This increase was primarily attributable to additional cost of revenues from the commencement of commercial operation of our Platanares power plant inHonduras , effectiveSeptember 2017 , ourTungsten Mountain power plant inNevada , effectiveDecember 2017 and commencement of commercial operation of our Plant 1 expansion project in theOlkaria III Complex inKenya , effectiveJune 2018 , (ii) approximately$8.0 million higher costs compared to the same period 2017 related to pump failures that we had to replace in some of our power plants and (iii) the consolidation of USG which we acquired onApril 24, 2018 . As a percentage of total Electricity segment revenues, the total cost of revenues attributable to our Electricity segment for the year endedDecember 31, 2018 was 58.5%, compared to 57.3% for the year endedDecember 31, 2017 . The cost of revenues attributable to our international power plants was 24.7% of our Electricity segment cost of revenues. Product Segment Total cost of revenues attributable to our Product segment for the year endedDecember 31, 2018 was$140.7 million , compared to$152.1 million for the year endedDecember 31, 2017 , representing a 7.5% decrease from the prior period. This decrease was primarily attributable to decrease in Product segment revenues, as discussed above. As a percentage of total Product segment revenues, our total cost of revenues attributable to the Product segment for the year endedDecember 31, 2018 was 69.7%, compared to 67.8% for the year endedDecember 31, 2017 . This increase was primarily attributable to the higher competition, different product scope and different margins in the various sales contracts we entered into for the Product segment during these periods.
Energy Storage and Management Services Segment
Cost of revenues attributable to our Energy Storage and Management Services segment for the year endedDecember 31, 2018 were$9.9 million , compared to$5.4 million for the year endedDecember 31, 2017 . The Energy Storage and Management Services segment includes cost of revenues related to the delivery of energy storage, demand response and energy management services by our Viridity business. 94
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Research and Development Expenses
Research and development expenses for the year ended
Selling and Marketing Expenses
Selling and marketing expenses for the year endedDecember 31, 2018 were$19.8 million , compared to$15.6 million for the year endedDecember 31, 2017 . This increase was primarily due to the$5.0 million termination fee paid to NV Energy related to the termination of the Galena 2 PPA. The increase was partially offset as a result of lower sales commissions related to our Product segment due to lower revenues and lower commissions due to the nature of the contracts. Selling and marketing expenses for the year endedDecember 31, 2018 , excluding the termination fee, constituted 2.1% of total revenues for such year, compared to 2.3% for the year endedDecember 31, 2017 .
General and Administrative Expenses
General and administrative expenses for the year endedDecember 31, 2018 were$47.8 million , compared to$42.9 million for the year endedDecember 31, 2017 . This increase was primarily attributable to (i) general and administrative expenses resulting from first time inclusion of USG, (ii) general and administrative expenses from our Viridity business which we acquired onMarch 15, 2017 ; and (iii) an increase in costs associated with our identification of a material weakness related to taxes in the fourth quarter of 2017 and the additional work and controls to compensate for such material weakness as well as the restatement of second, third and fourth quarter financial statements and its full-year 2017 financial statements and related expenses. The increase was partially offset due to a$10.3 million adjustment in respect of an earn out related to the acquisition of our Viridity business. General and administrative expenses for the year endedDecember 31, 2017 included$2.1 million charge for stock-based compensation expense associated with the acceleration of the vesting period of the stock options previously held by our CEO and CFO and exercised in connection with ORIX's acquisition of 22% of our Company. Goodwill Impairment Charge
Write-off of Unsuccessful Exploration Activities
Write-off of unsuccessful exploration activities for the year endedDecember 31, 2018 was$0.1 million , compared to$1.8 million for the year endedDecember 31, 2017 . The write-off of unsuccessful exploration activities for the year endedDecember 31, 2017 , included costs related to the Glass Buttes site inOregon , which we determined in the fourth quarter of 2017, would not support commercial operations. Operating Income Operating income for the year endedDecember 31, 2018 was$185.1 million , compared to$205.0 million for the year endedDecember 31, 2017 , representing a 9.7% decrease from the prior period. The decrease in operating income was primarily attributable to the$13.5 million goodwill impairment charge, the decrease in our Product segment gross margin, the$5.0 million termination fee of the Galena 2 PPA, and the increase in general and administrative expenses, as discussed above. The decrease was partially offset by an increase in our gross margin in our Electricity segment, also discussed above. Operating income attributable to our Electricity segment for the year endedDecember 31, 2018 was$155.5 million , compared to$157.6 million for the year endedDecember 31, 2017 . Operating income attributable to our Product segment for the year endedDecember 31, 2018 was$38.1 million , compared to$50.5 million for the year endedDecember 31, 2017 . Operating loss attributable to our Energy Storage and Management Services segment for the year endedDecember 31, 2018 was$8.5 million compared to a loss of$3.1 million for the year endedDecember 31, 2017 . 95
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Table of Contents Interest Expense, Net Interest expense, net, for the year endedDecember 31, 2018 was$70.9 million , compared to$54.1 million for the year endedDecember 31, 2017 , representing a 31.0% increase from the prior period. This increase was primarily due to: (i)$100.0 million of proceeds from a senior unsecured loan received onMarch 22, 2018 ; (ii) net increase in our revolving credit lines with commercial banks; and (iii) a$3.5 million increase related to a decrease in interest capitalized to projects; (iv) additional debt as part of the acquisition of USG, and (v)$4.3 million increase in interest related to the sale of tax benefits; and (vi)$114.7 million of proceeds from a limited recourse loan received onOctober 29, 2018 from OPIC for financing theHonduras power plant, offset partially due to lower interest expense as a result of principal payments of long term debt.
Derivatives and Foreign Currency Transaction Losses
Derivatives and foreign currency transaction losses for the year endedDecember 31, 2018 were$4.8 million , compared to gains of$2.7 million for the year endedDecember 31, 2017 . Derivatives and foreign currency transaction losses for the year endedDecember 31, 2018 were attributable primarily to losses from foreign currency forward contracts, which were not accounted for as hedge transactions. Derivatives and foreign currency transaction gains for the year endedDecember 31, 2017 were primarily attributable to gains from foreign currency forward contracts, which were not accounted for as hedge transactions.
Income Attributable to Sale of Tax Benefits
Tax equity is a form of financing used for renewable energy projects. In such financings, the Company we may realize income when the financing is put in place or over time as a consequence of how the financing is structured. Income attributable to the sale of tax benefits to institutional equity investors (as described in our financial statements below under "OPC Transaction", "ORTP Transaction" and "Opal Geo Transaction") for the year endedDecember 31, 2018 was$19.0 million , compared to$17.9 million for the year endedDecember 31, 2017 . This income primarily represents the value of PTCs and taxable income or loss generated byOpal Geo and Tungsten allocated to the investor in the year endedDecember 31, 2018 compared to the value of PTCs and taxable income or loss generated byOpal Geo allocated to the investors in the year endedDecember 31, 2017 .
Other Non-Operating Income (loss)
Other non-operating income, net for the year endedDecember 31, 2018 was$7.8 million , compared to Other non-operating expense, net of$1.7 million for the year endedDecember 31, 2017 . Other non-operating expense, net for the year endedDecember 31, 2018 includes an income of$7.2 million insurance settlement of our Puna power plant rig which was damaged by theKilauea volcanic eruption. Other non-operating expense, net for the year endedDecember 31, 2017 includes a make whole premium of$1.9 million resulting from the prepayment of$14.3 million aggregate principal amount of our OFC Senior Secured Notes and$11.8 million aggregate principal amount of our DEG Loan.
Income from operations, before income taxes and equity in losses of investees
Income from operations, before income taxes and equity in losses of investees for the year endedDecember 31, 2018 was$137.2 million , compared to$170.7 million for the year endedDecember 31, 2017 , representing a 19.7% decrease from the prior period. The income is primarily attributable to our foreign operations. This decrease was driven by the decrease in our domestic operations resulting mainly from the goodwill impairment charge relating to our Viridity business, the$5.0 million termination fee of the Galena 2 PPA, and the increase in general and administrative expenses, partially offset by an income of$7.2 million insurance settlement of our Puna power plant rig in the year endedDecember 31, 2018 , as described above. Income Taxes Income tax provision for the year endedDecember 31, 2018 , was$34.7 million , an increase of$13.0 million compared to an income tax provision of$21.7 million for the year endedDecember 31, 2017 . The increase in income tax provision primarily resulted from the tax on global intangible low-tax income (GILTI), partially offset by a decrease in withholding tax on distribution of earnings, and the exclusion of other impacts ofU.S. federal tax reform that resulted in a one-time tax impact for the year endedDecember 31, 2017 . Our effective tax rate for the years endedDecember 31, 2018 and 2017, was 25.3% and 12.7%, respectively. Our effective tax rate atDecember 31, 2018 is principally based upon the composition of the income in different countries, tax on GILTI, accounting for intra-entity transfers of assets other than inventory, and changes related to valuation allowances. Our aggregate effective tax rate is higher than the 21%U.S federal statutory tax rate due to: (i) the impact of the newly enacted GILTI; (ii) higher tax rate inKenya of 37.5% andGuadeloupe of 33.33% partially offset by a lower tax rate inIsrael of 16 %; and (iii) withholding taxes on future distributions (see Note 18 - Income Taxes to the consolidated financial statements set forth in Item 8 of this annual report for further details regarding our income tax provision and the Tax Act). 96
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For the years endedDecember 31, 2018 and 2017, we recorded a valuation allowance in the amount of approximately$22.4 million and$77.6 million , respectively, against our unutilized tax credits (FTCs and PTCs) andU.S. deferred tax assets related to state net operating loss (NOL) carryforwards. As ofDecember 31, 2018 , we hadU.S. federal NOLs in the amount of approximately$230.5 million , state NOLs in the amount of approximately$269.1 million , and unutilized federal tax credits of approximately$149.0 million , some of which can be carried forward for 10-20 years. In addition, we had unutilized state tax credits of approximately 0.8 million, which can be carried forward for indefinite period. The related deferred tax assets totaled approximately$192.4 million after valuation allowance. Realization of these deferred tax assets and tax credits is dependent on generating sufficient taxable income inthe United States prior to expiration of the NOL carryforwards and tax credits. The scheduled reversal of deferred tax liabilities, projected future taxable income, estimated impacts of tax reform and tax planning strategies were considered in determining the amount of valuation allowance. A valuation allowance in the amount of$22.4 million was recorded against theU.S. deferred tax assets as ofDecember 31, 2018 because we believe it is more likely than not that the deferred tax assets will not be realized. If sufficient additional evidence of our ability to generate taxable income is established, we may be required to reduce or fully release the valuation allowance, resulting in income tax benefits in our consolidated statement of operations. OnDecember 22, 2017 , theU.S. government signed into law the Tax Act. The Tax Act makes significant changes to theU.S. tax code, including, but not limited to, (1) reducing theU.S. federal corporate income tax rate from 35 percent to 21 percent; (2) the transition ofU.S. international taxation from a worldwide tax system to a territorial system (GILTI, BEAT, Dividends Received Deduction); (3) one-time transition tax on undistributed earnings of foreign subsidiaries as ofDecember 31, 2017 ; (4) eliminating the corporate alternative minimum tax (5) creating a new limitation on deductible interest expense; and (6) changing rules related to uses and limitations of net operating loss carryforwards created in tax years beginning afterDecember 31, 2017 . We applied the guidance ofSAB 118 for the effects of the Tax Act in 2017 and throughout 2018. The Deemed Repatriation Tax (Transition Tax) is a tax on previously untaxed accumulated and current earnings and profits (E&P) of certain foreign subsidiaries. To determine the amount of the Transition Tax, we determined, in addition to other factors, the amount of post-1986 E&P of the relevant subsidiaries, as well as the amount of non-U.S. income taxes paid on such earnings. As a result of our initial analysis of the impact of the Tax Act, we recorded a provisional amount of$71.6 million (gross) with respect to the inclusion of the transition tax atDecember 31, 2017 . In addition, atDecember 31, 2017 , we recorded a provisional benefit of$22.6 million relating to the remeasurement of deferred taxes from 35% to 21%. As ofDecember 31, 2018 , we have completed our accounting for the tax effects of the Tax Reform Act. Subsequent adjustments to these amounts resulted in a reduction of$7.8 million to the transition tax and a decreased tax benefit of$3.5 million to the remeasurement of deferred taxes. Under the Tax Act, the deductibility of net interest for a business is limited to 30% of adjusted taxable income. The new proposed regulations issued byTreasury applies regardless of whether the interest payment is made to aU.S. or foreign person, whether the interest recipient is related, or whether the interest recipient is exempt fromU.S. tax. Further, any interest that cannot be deducted in a year can be carried forward indefinitely. We have not early adopted these proposed regulations and intend to adopt them during the 2019 tax year. For the year endedDecember 31, 2018 , we have evaluated the impact and determined there is no limit on our interest deductibility for federal income tax purposes for the current period, but anticipates there could be significant limitations upon adoption. We are also required to elect to either treat taxes due on future GILTI inclusions inUnited States taxable income as a current period expense when incurred or reflect such portion of the future GILTI inclusions inUnited States taxable income that relate to existing basis differences in our current measurement of deferred taxes. We have elected to treat the taxes due on futureU.S. inclusions in taxable income under GILTI as a period cost when incurred. We have elected and applied the tax law ordering approach when considering GILTI as part of our valuation allowance. We continue to monitor the impact of any additional guidance issued byTreasury . Notwithstanding the reduction in the corporate income tax rate, the overall impact of the Tax Act is uncertain, and our business, financial condition, future results and cash flow, as well as our stock price, could be adversely affected. 97
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Equity in Earnings (losses) of Investees, Net
Equity in earnings (losses) of investees, net in the year endedDecember 31, 2018 was a profit of$7.7 million , compared to a loss of$2.0 million in the year endedDecember 31, 2017 . Equity in earnings (losses) of investees, net derived from our 12.75% share in the losses of the Sarulla complex and from profits elimination.The increase was mainly attributable to utilization of carryforward losses and full year of commercial operations of SIL and NIL 1 and commercial operation of NIL 2 fromMay 2018 . Net Income Net income for the year endedDecember 31, 2018 was$110.1 million , compared to$147.1 million for the year endedDecember 31, 2017 , representing a decrease of$37.0 million from the prior period. This decrease in net income was primarily attributable to a decrease in operating income of$19.9 million , an increase of$16.8 million in interest expense, net and a decrease of$7.4 million in derivatives and foreign currency transaction gains and$13.1 million increase in income tax provision, partially offset due to an increase in Other non-operating income, net of$9.4 million , and an increase in equity in earnings of investees, net of$9.6 million , all as discussed above.
Net Income attributable to the Company's Stockholders
Net income attributable to the Company's stockholders for the year endedDecember 31, 2018 was$98.0 million , compared to$132.4 million for the year endedDecember 31, 2017 , which represents a decrease of$34.4 million . This decrease was attributable to the decrease in net income of$37.0 million , offset partially by a decrease of$2.6 million in net income attributable to noncontrolling interest mainly due to the shutdown of the Puna power plant inHawaii , all as discussed above.
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, 2019 , we had access to: (i)$71.2 million in cash and cash equivalents, of which$59.2 million was held by our foreign subsidiaries; and (ii)$213.9 million of unused corporate borrowing capacity under existing lines of credit with different commercial banks. Our estimated capital needs for 2020 include approximately$332 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$135.5 million for long-term debt repayments, which excludes$50.0 million of commercial papers and approximately$40.6 million for revolver that we assume will be renewed.
As of
We expect to finance these requirements with: (i) the sources of liquidity described above; (ii) positive cash flows from our operations; and (iii) future project financings and re-financings (including construction loans and tax equity). Management believes that, based on the current stage of implementation of our strategic plan, the sources of liquidity and capital resources described above will address our anticipated liquidity, capital expenditures, and other investment requirements. During 2019, we have revised our assertion to no longer indefinitely reinvest foreign funds held by our foreign subsidiaries, with the exception of a certain balance held inIsrael and have accrued the incremental foreign withholding taxes. As a result, we have further liquidity to move funds freely. Third-Party Debt Our third-party debt consists of (i) non-recourse and limited-recourse project finance debt or acquisition financing that we or our subsidiaries have obtained for the purpose of developing and constructing, refinancing or acquiring our various projects and (ii) full-recourse debt incurred by us or our subsidiaries for general corporate purposes. 98
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Non-Recourse and Limited-Recourse Third-Party Debt
Loan Issued Outstanding Interest Maturity Related Location Amount Amount as Rate Date Projects ($M) of December 31, 2019 McGinness Hills OFC 2 Senior Secured phase 1 and Notes - Series A 151.7 94.3 4.82% 2032 Tuscarora United States OFC 2 Senior Secured McGinness Hills Notes - Series B 140.0 108.8 4.61% 2032 phase 2 United States Olkaria III Financing Agreement with OPIC - Olkaria III Tranche 1 85.0 51.9 6.34% 2030 Complex Kenya Olkaria III Financing Agreement with OPIC - Olkaria III Tranche 2 180.0 111.2 6.29% 2030 Complex Kenya Olkaria III Financing Agreement with OPIC - Olkaria III Tranche 3 45.0 29.6 6.12% 2030 Complex Kenya Amatitlan Financing (1) 42.0 26.3 LIBOR+4.35% 2027 Amatitlan Guatemala Don A. Don A. Campbell Senior Campbell Secured Notes 92.5 78.2 4.03% 2033 Complex United States Neal Hot Prudential Capital Springs and Raft Group Idaho Loan (2) 20.0 18.3 5.8% 2023 River United States U.S. Department of Neal Hot Energy loan (3) 96.8 44.9 2.61% 2035 Springs United States Prudential Capital Group Nevada Loan 30.7 27.1 6.75% 2037 San Emidio United States Platanares Loan with OPIC 114.7 104.5 7.02% 2032 Platanares Honduras Viridity - Plumstriker 23.5 21.6 LIBOR+3.5% 2026 Plumsted+Striker United States Geothermie Bouillante Geothermie (4) 8.9 8.4 1.52% 2026 Bouillante Guadeloupe Geothermie Bouillante Geothermie (4) 8.9 9.0 1.93% 2026 Bouillante Guadeloupe Total 1,039.7 734.1
(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 6.29%.
(2) Secured by equity interest.
(3) Secured by the assets.
(4) Loan in Euros and issued amount is
Full-Recourse Third-Party Debt
Loan Issued Outstanding Interest Maturity Amount as of Rate Date ($M) December 31, 2019 Senior Unsecured Bonds Series 2 67.2 67.2 3.7% September 2020 Senior Unsecured Bonds Series 3 137.1 137.1 4.45% September 2022 3 month Commercial Paper(1) 50.0 50.0 LIBOR+0.75% (2) Short term revolving 40.6 credit lines with banks Senior unsecured Loan 1 100.0 100.0 4.8% March 2029 Senior unsecured Loan 2 50.0 50.0 4.6% March 2029 DEG Loan 2 50.0 42.5 6.28% June 2028 DEG Loan 3 41.5 37.1 6.04% June 2028 Total 495.8 524.5
(1) Current interest rate is 2.69%.
(2) Issued for 90 days and extends automatically for additional periods of 90 days each for up to five years.
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Letters of Credits under the Credit Agreements
Some of our customers require our project subsidiaries to post letters of credit in order to guarantee their respective performance under relevant contracts. We are also required to post letters of credit to secure our obligations under various leases and licenses and may, from time to time, decide to post letters of credit in lieu of cash deposits in reserve accounts under certain financing arrangements. In addition, our subsidiary, Ormat Systems is required from time to time to post performance letters of credit in favor of our customers with respect to orders of products. Credit Agreements Issued Issued and Termination Amount Outstanding as Date ($M) of December 31, 2019 MUFG 60.0 59.5 June 2020 HSBC 35.0 25.5 October 2020 Other Institutions 260.0 15.6 March 2020 - July 2022 Other Banks 1 150.0 103.1 September 2020 - July 2022 Other Banks 2 - 10.1 December 2020 Total 505.0 213.8 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$600 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 35% of net income in any calendar year. As ofDecember 31, 2019 : (i) total equity was$1,515.4 million and the actual equity to total assets ratio was 46.6% and (ii) the 12-month debt, net of cash, cash equivalents, to Adjusted EBITDA ratio was 2.99. During the year endedDecember 31, 2019 , we distributed interim dividends in an aggregate amount of$22.4 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. 100
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Table of Contents Future minimum payments Future minimum payments under long-term obligations, excluding revolving credit lines with commercial banks, as ofDecember 31, 2019 , are detailed under the caption Contractual Obligations and Commercial Commitments, below.
Puna Power Plant Lease Transactions
In
In connection with the execution of the new amended and restated PPA described under "Recent Developments" above, we paid$20.5 million to effectively terminate the lease transactions (the amount includes all future payments according to the original lease agreements) involving the original power plant in order to enter into and meet our obligations under the new PPA. As a result, we have no obligation for future minimum lease payments as ofDecember 31, 2019 .
Liquidity Impact of Uncertain Tax Positions
As discussed in Note 18 - 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$14.6 million as ofDecember 31, 2019 . This liability is included in long-term liabilities in our consolidated balance sheet, because we generally do not anticipate that settlement of the liability will require payment of cash within the next 12 months. We are not able to reasonably estimate when we will make any cash payments required to settle this liability. Dividends
The following are the dividends declared by us during the past two years:
Dividend Amount per Date Declared Share Record Date Payment Date March 1, 2018$ 0.23 March 14, 2018 March 29, 2018 May 7, 2018$ 0.10 May 21, 2018 May 30, 2018 August 7, 2018$ 0.10 August 21, 2018 August 29, 2018 November 6, 2018$ 0.10 November 20, 2018 December 4, 2018 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 Historical Cash Flows The following table sets forth the components of our cash flows for the relevant periods indicated: Year Ended December 31, 2019 2018 2017 (Dollars in thousands)
Net cash provided by operating activities
$ 245,575 Net cash used in investing activities (254,538 ) (342,434 ) (345,526 ) Net cash provided by (used in) financing activities (5,765 ) 251,131 (67,882 ) Translation adjustments on cash and cash equivalents (575 ) (660 ) - Net change in cash and cash equivalents and restricted cash and cash equivalents$ (24,385 ) $ 53,859 $ (167,833 ) 101
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For the Year Ended
Net cash provided by operating activities for the year endedDecember 31, 2019 was$236.5 million , compared to$145.8 million for the year endedDecember 31, 2018 . This increase of$99.1 million resulted primarily from (i) an increase in accounts payable and accrued expenses of$8.7 million in the year endedDecember 31, 2019 , compared to a decrease of$56.7 million in the year endedDecember 31, 2018 , driven by: (i) a withholding tax payment of approximately$14 million in the year endedDecember 31, 2019 compared to$44 million in the year endedDecember 31, 2018 , because of a distribution from OSL (ii) the timing of payments to our suppliers and (iii) a decrease of$15.1 million in receivables in the year endedDecember 31, 2019 compared to$29.9 million in the year endedDecember 31, 2018 because of timing of collections from our customers. Net cash used in investing activities for the year endedDecember 31, 2019 was$254.5 million , compared to$342.4 million for the year endedDecember 31, 2018 . The principal factors that affected our net cash used in investing activities during the year endedDecember 31, 2019 were: (i) capital expenditures of$280.0 million , primarily for our facilities under construction; and (ii) an investment in an unconsolidated company of$10.7 million , partially offset by proceeds from insurance recoveries of$35.4 million . Net cash used in financing activities for the year endedDecember 31, 2019 was$5.8 million , compared to$251.1 million provided by financing activities for the year endedDecember 31, 2018 . The principal factors that affected the net cash used in financing activities during the year endedDecember 31, 2019 were: (i) net payment of$118.5 million from our revolving credit lines with commercial banks which were used for capital expenditures, (ii) the repayment of long-term debt in the amount of$93.8 million ; (iii) a$22.4 million cash dividend payment and (iv)$9.7 million cash paid to a noncontrolling interest, partially offset by, (i)$50 million of proceeds from a senior unsecured loan, (ii)$41.5 million of proceeds from a term loan for ourOlkaria III Complex plant 1 expansion, (iii)$23.5 million of proceeds for the financing of two 20 MW battery energy storage projects, (iv)$17.8 million of proceeds from limited and non-recourse loans for ourGuadeloupe power plant, (v)$50.0 million of proceeds from issuance of commercial paper and (vi) proceeds from the sale of a limited liability company interest in McGinness Hills Phase 3, net of transaction costs of$58.3 million .
For the Year Ended
Net cash provided by operating activities for the year endedDecember 31, 2018 was$145.8 million , compared to$245.6 million for the year endedDecember 31, 2017 . This decrease of$99.8 million resulted primarily from a decrease in accounts payable and accrued expenses of$56.7 million in the year endedDecember 31, 2018 , compared to an increase of$51.6 million in the year endedDecember 31, 2017 , mainly due to a withholding tax payment of approximately$44 million due to a distribution from OSL, offset partially by approximately$14 million due to a distribution from OSL in 2018. The decrease was also due to timing of payments to our suppliers. Net cash used in investing activities for the year endedDecember 31, 2018 was$342.4 million , compared to$345.5 million for the year endedDecember 31, 2017 . The principal factors that affected our net cash used in investing activities during the year endedDecember 31, 2018 were: (i) capital expenditures of$258.5 million , primarily for our facilities under construction; (ii) cash paid for acquisition of controlling interest in USG, net of cash acquired of$95.1 million ; and (iii) an investment in an unconsolidated company of$3.8 million . Net cash used in financing activities for the year endedDecember 31, 2018 was$251.1 million , compared to$67.9 million provided by financing activities for the year endedDecember 31, 2017 . The principal factors that affected the net cash provided by financing activities during the year endedDecember 31, 2018 were: (i)$100.0 million of proceeds from a senior unsecured loan, (ii)$114.7 million of proceeds from a limited and non-recourse loan; (iii) net proceeds of$107.5 million from our revolving credit lines with commercial banks which were used for capital expenditures, and (iv) proceeds from the sale of a limited liability company interest in Tungsten, net of transaction costs of$32.2 million , partially offset by: (i) the repayment of long-term debt in the amount of$62.8 million ; (ii) a$26.8 million cash dividend paid; and (iii)$13.1 million of cash paid to noncontrolling interests. 102
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Total EBITDA and Adjusted EBITDA
We calculate EBITDA as net income before interest, taxes, depreciation and amortization. We calculate Adjusted EBITDA as net income before interest, taxes, depreciation and amortization, adjusted for (i) termination fees, (ii) impairment of long-lived assets, (iii) write-off of unsuccessful exploration activities, (iv) any mark-to-market gains or losses from accounting for derivatives, (v) merger and acquisition transaction costs, (vi) stock-based compensation, (vii) gain or loss from extinguishment of liabilities, (viii) gain or loss on sale of subsidiary and property, plant and equipment and (ix) other unusual or non-recurring items. EBITDA and Adjusted EBITDA are not measurements of financial performance or liquidity under accounting principles generally accepted inthe United States , orU.S. GAAP, and should not be considered as an alternative to cash flow from operating activities or as a measure of liquidity or an alternative to net earnings as indicators of our operating performance or any other measures of performance derived in accordance withU.S. GAAP. We use EBITDA and Adjusted EBITDA as a performance metric because it is a metric used by our Board of Directors and senior management in evaluating our financial performance. However, other companies in our industry may calculate EBITDA and Adjusted EBITDA differently than we do. This information should not be considered in isolation from, or as a substitute for, or superior to, measures of financial performance prepared in accordance with GAAP or other non-GAAP financial measures.
Adjusted EBITDA for the year ended
The following table reconciles net income to EBITDA and adjusted EBITDA for the
years ended
Year Ended December 31, 2019 2018 2017 (Dollars in thousands) Net income$ 93,543 $ 110,111 $ 147,109 Adjusted for: Interest expense, net (including amortization of deferred financing costs) 78,869 69,950
53,154
Income tax provision (benefit) 45,613 34,733
21,664
Adjustment to investment in an unconsolidated company: our proportionate share in interest expense, tax and depreciation and amortization in Sarulla complex 13,089 9,184 (265 ) Depreciation and amortization 143,242 127,732
108,693
EBITDA 374,356 351,710
330,355
Mark-to-market on derivative instruments (1,402 ) 2,032 (1,500 ) Stock-based compensation 9,358 10,218
8,760
Insurance proceeds in excess of assets carrying value - (7,150 ) - Termination fee - 3,142 - Impairment of goodwill, net of reversal of a contingent liability - 4,973 - Loss from extinguishment of liability 468 -
1,950
Merger and acquisition transaction costs 1,483 2,910
2,460
Write-off of unsuccessful exploration activities - 126 1,796 Adjusted EBITDA$ 384,263 $ 367,961 $ 343,821
Adjusted EBITDA excluding the impact of Puna related expenses of approximately
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, 2019 , the credit facility has an outstanding balance of$1,074.2 million . Our proportionate share in the SOL credit facility is$137.0 million . 103
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Table of Contents 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$359 million in capital expenditures for construction of new projects and enhancements to our existing power plants, of which we had invested$96.2 million as ofDecember 31, 2019 . We expect to invest approximately$134 million in 2020 and the remaining approximately$128 million thereafter. In addition, we estimate approximately$198 million in additional capital expenditures in 2020 to be allocated as follows: (i) approximately$57 million for the exploration and development of new projects and enhancements of existing power plants that not yet released for full construction (ii) approximately$61 million for maintenance of capital expenditures to our operating power plants including drilling in our Puna power plant; (iii) approximately$65 million for the construction and development of storage projects; and (iv) approximately$15.0 million for enhancements to our production facilities.
In the aggregate, we estimate our total capital expenditures for 2020 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. The energy payments under the PPAs of theHeber 2 power plant in theHeber Complex and the G2 power plant inMammoth 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 a result of the high fuel costs that impact HELCO's avoided costs. As ofDecember 31, 2019 , 95.9% of our consolidated long-term debt was fixed rate debt and therefore was not subject to interest rate volatility risk and 4.1% of our long-term debt was floating rate debt, exposing us to interest rate risk in connection therewith. As ofDecember 31, 2019 ,$47.9 million of our long-term debt remained subject to some interest rate risk. 104
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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. We are also exposed to foreign currency exchange risk, in particular the fluctuation of theU.S. dollar versus the NIS inIsrael and KES inKenya . 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 contracts in place to reduce our foreign 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. In the three months endedDecember 31, 2019 , our exchange rate exposure inKenya resulted in an expense of approximately$2.5 million . We performed a sensitivity analysis on the fair values of our long-term debt obligations, and foreign currency exchange forward contracts. The foreign currency exchange forward contracts listed below principally relate to trading activities. The sensitivity analysis involved increasing and decreasing forward rates atDecember 31, 2019 and 2018 by a hypothetical 10% and calculating the resulting change in the fair values.
At this time, the development of our new strategic plan has not exposed us to any additional market risk. However, as the implementation of the plan progresses, we may be exposed to additional or different market risks.
The results of the sensitivity analysis calculations as of
Assuming a 10% Assuming a 10% Increase in Rates Decrease in Rates As of December 31, As of December 31, Risk 2019 2018 2019 2018
Change in the Fair Value of
(In thousands) Foreign Currency Forward Foreign Currency$ (4,198 ) $ (4,042 ) $ 5,131 $ 4,940 Contracts Interest Rate $ -$ (113 ) $ -$ 114 OrCal Senior Secured Notes Interest Rate$ (4,574 ) $ (5,955 ) $ 4,723 $ 6,211 OFC 2 Senior Secured Notes Interest Rate$ (4,647 ) $ (6,022 ) $ 4,812 $ 6,294 OPIC Loan Interest Rate$ (516 ) $ (714 ) $ 534 $ 745 Amatitlan loan Interest Rate$ (1,797 ) $ (3,054 ) $ 1,822 $ 3,118 Senior Unsecured Bonds Interest Rate$ (905 ) $ (1,216 ) $ 934 $ 1,266 DEG 2 Loan Interest Rate$ (1,835 ) $ (2,324 ) $ 1,906 $ 2,438 DAC 1 Senior Secured Notes Migdal Loan and the Additional Interest Rate$ (3,272 ) $ (2,897 ) $ 3,363 $ 3,010 Migdal Loan Interest Rate$ (1,141 ) $ (1,306 ) $ 1,207 $ 1,398 San Emidio Loan Interest Rate$ (776 ) $ (1,153 ) $ 797 $ 1,197 DOE Loan Interest Rate$ (281 ) $ (440 ) $ 286 $ 453 Idaho Holdings Loan Interest Rate$ (2,978 ) $ (3,719 ) $ 3,099 $ 3,907 Platanares OPIC Loan Interest Rate$ (728 ) $ -$ 749 $ - DEG 3 Loan Interest Rate$ (342 ) $ -$ 350 $ - Plumstriker Loan Interest Rate$ (295 ) $ -$ 298 $ - Commercial Paper Interest Rate$ (201 ) $ (143 ) $ 204 $ 148 Other long-term loans InJuly 2019 , theUnited 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. TheU.S. Federal Reserve , in conjunction with the Alternative Reference Rates Committee, a steering committee comprised of largeU.S. financial institutions, is considering replacingU.S. dollar LIBOR with a new SOFR (Secured Overnight Financing Rate) index calculated by short-term repurchase agreements, backed byTreasury securities. 105
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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 rising inflation some of our contracts include certain provisions that mitigate inflation risk.
In connection with the Electricity segment, none of ourU.S. PPAs, including the SCPPA Portfolio PPA, are directly linked to the CPI. Inflation may directly impact an expense we incur for the operation of our projects, thereby increasing our overall operating costs and reducing our profit and gross margin. The negative impact of inflation would be partially offset by price adjustments built into some of our PPAs that could be triggered upon such occurrences. The energy payments pursuant to our PPAs for some of our power plants such as the Brady power plant, the Steamboat 2 and 3 power plants and theMcGinness Complex , increase every year through the end of the relevant terms of such agreements, although such increases are not directly linked to the CPI or any other inflationary index. Lease payments are generally fixed, while royalty payments are generally calculated as a percentage of revenues and therefore are not significantly impacted by inflation. In our Product segment, inflation may directly impact fixed and variable costs incurred in the construction of our power plants, thereby increasing our operating costs in the Product segment. We are more likely to be able to offset all or part of this inflationary impact through our project pricing. With respect to power plants that we build for our own electricity production, inflationary pricing may impact our operating costs which may be partially offset in the pricing of the new long-term PPAs that we negotiate.
Contractual Obligations and Commercial Commitments
The following tables set forth our material contractual obligations as of
Payments Due by Period Remaining Total 2020 2021 2022 2023 2024 Thereafter Long-term liabilities principal$ 1,167,912 $ 135,504 $ 76,259 $ 220,677 $ 98,982 $ 78,600 $ 557,890 Interest on long-term liabilities (1) 336,593 58,555 52,228 47,931 44,593 32,061 101,225 Finance lease obligations 19,854 4,251 3,948 3,873 2,758 906 4,118 Operating lease obligations 20,956 2,742 2,701 2,079 1,524 1,275 10,635 Benefits upon retirement (2) 19,803 4,780 1,434 1,768 89 500 11,232 Asset retirement obligation 50,183 - - - - - 50,183 Purchase commitments (3) 184,985 184,985 - - - - -$ 1,800,286 $ 390,817 $ 136,570 $ 276,328 $ 147,946 $ 113,342 $ 735,283
(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
2019, total obligations related to such supplier agreements were
approximately
construction-in-process). All such obligations are payable in 2020. 106
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The table above does not reflect unrecognized tax benefits of$14.6 million , the timing of which is uncertain. Refer to Note 18 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$123.5 million , the timing of which is uncertain and other long-term liabilities of$6.8 million that are deemed immaterial. Refer to Note 13 to our consolidated financial statements as set forth in Item 8 of this annual report for additional discussion of our liability associated with the sale of tax benefits. Concentration of Credit Risk Our credit risk is currently concentrated with the following major customers:Sierra Pacific Power Company andNevada Power Company (subsidiaries of NV Energy), 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.Sierra Pacific Power Company andNevada Power Company accounted for 17.1%, 16.1% and 18.1% of our total revenues for the three years endedDecember 31, 2019 , 2018 and 2017, respectively.
KPLC accounted for 16.3%, 16.6%, and 15.9% of our total revenues for the three
years ended
SCPPA accounted for 17.9%, 15.2% and 10.1% of our total revenues for the three
years ended
We have historically been able to collect on substantially all of our receivable balances. As ofDecember 31, 2019 , the amount overdue from KPLC inKenya was$40.7 million of which$24.2 million was paid in January and February of 2020. These amounts are an average of 70 days overdue, an increase of 10 days fromSeptember 30, 2019 . InHonduras , we began collecting current charges from ENEE inMay 2019 ; however, as ofDecember 31, 2019 , the amount overdue relating to the period fromOctober 2018 toApril 2019 is$20.1 million , none of which has been paid to date. Due to obligations of the Honduran government to support us, we believe we will be able to collect all past due amounts.
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 2019 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 afterJanuary 1, 2021 .
• ITC - the ITC rules have been amended a number of times. A qualified new
geothermal power plant in
end of 2020 would be eligible to claim an ITC of 30% of the project cost. New
solar projects that were under construction by
a 30% ITC. The credit will phasedown to 26% for solar PV projects starting
construction in 2020 and to 22% for solar PV projects starting construction in
2021. Projects that were under construction before these deadlines must be
placed in service by
solar projects placed in service after
a 10% ITC. Under current tax rules, any unused tax credit has a one-year carry
back and a twenty-year carry forward. 107
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• On
made changes that have some impact on the renewable energy industry. Some of
the key changes are as follows:
• The
2018.
• Bonus depreciation was increased from 40% expensing of qualified projects in
year one to 100% beginning in on
valid through 2022 and then declines through 2026. • The BEAT provision is a new tax intended to apply to companies that
significantly reduce their
to affiliates. The provision aims to circumvent earnings stripping by imposing
a minimum tax of 10% of taxable income. ITC and PTC can be used to offset
approximately 80% BEAT. See the discussion under Item 1A - "Risk Factors".
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.Kenya tax audit
The Company received three letters from the
The first Letter of Preliminary Findings was received inMarch 2019 , which was followed by a Notice of Assessment duringJune 2019 in which the KRA demanded approximately$5.6 million from the Company, including interest and penalties in respect of two certain issues relating to its review of tax years 2014 to 2017. InJuly 2019 , the Company responded to the KRA Notice of Assessment primarily objecting to one of the two issues raised in the assessment, consisting of approximately$4.4 million , and asked the KRA to vacate this issue as set forth in its tax assessment letter. The Company received the second Letter of Preliminary Findings ("the Second Letter of Preliminary Findings") from the KRA inJuly 2019 , which relates to findings from the KRA's audit review for tax years 2013 to 2017. InAugust 2019 , the Company filed its response to the Second Letter of Preliminary Findings, contesting the KRA arguments and requesting that the KRA vacate all issues set forth in its Letter of Preliminary Findings. InDecember 2019 , the KRA submitted its audit assessment letter in relation to the 2013 to 2017 tax years in which it demanded approximately$205 million from the Company, including interest and penalties in respect of the issues included in its Second Letter of Preliminary Findings. InJanuary 2020 , the Company responded to the KRA objecting to all the issues raised in the tax assessment for tax years 2013 to 2017 and asked the KRA to vacate all issues set forth in its tax assessment letter. The Company received the third Letter of Preliminary Findings (the "Third Letter of Preliminary Findings") from the KRA inDecember 2019 relating to the same tax years in which the KRA set forth an additional demand for approximately$17 million , including interest and penalties, in relation to an additional audit finding which was not previously included in the KRA's assessments. InJanuary 2020 , the Company filed a formal objection to the Third Letter of Preliminary Findings, contesting the KRA's finding. The Company is currently at different stages of discussions with the KRA on the matters included in the KRA letters of assessment and preliminary findings as described above and believes its tax positions for the issues raised during the audit period is more-likely-than-not sustainable based on technical merits under Kenyan tax law. As ofDecember 31, 2019 , the Company has not recorded any tax reserves related to these demands except for an immaterial amount included in the first Letter of Preliminary Findings.
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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