ORMAT TECHNOLOGIES : MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (form 10-K)

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 December 31, 2019, our total revenues increased by 3.7% (from $719.3 million to $746.0 million) over the previous year.

For the year ended December 31, 2019, Electricity segment revenues were $540.3
million, compared to $509.9 million for the year ended December 31, 2018, an
increase of 6.0%. Product segment revenues for the year ended December 31, 2019
were $191.0 million, compared to $201.7 million for the year ended December 31,
2018, a decrease of 5.3%. Energy Storage and Management Services segment
revenues for the year ended December 31, 2019 were $14.7 million, compared to
$7.6 million for the year ended December 31, 2018.

During the years ended December 31, 2019 and 2018, our consolidated power plants generated 6,238,272 MWh and 5,857,963 MWh, respectively, an increase of 6.5%.

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For the year ended December 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 ended December 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 in
California and Hawaii, 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 California for each Heber 2 power plant in

the Heber Complex and the G2 power plant in the Mammoth Complex, a total of

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 Puna Complex

in Hawaii change primarily as a result of variations in the price of oil as

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 February 2020, we announced a transition of its senior management. Mr.

Isaac Angel has decided to retire from his position as Chief Executive

Officer, effective July 1, 2020, after six years of successful service to the

Company, its employees and its shareholders. It is intended that Mr. Angel

will become a member of Ormat's Board of Directors before his retirement as

Chief Executive Officer and will continue to be employed by the Company

through December 31, 2020 in order to assist with the management transition.

Ormat's Board of Directors has appointed Mr. Blachar, the Company's President

and Chief Financial Officer, to succeed Mr. Angel. Mr. Blachar will assume

the role of Chief Executive Officer on July 1, 2020 upon Mr. Angel's

retirement.

Mr. Blachar will be succeeded in his role as Chief Financial Officer by Assaf

Ginzburg, effective May 10, 2020, at which point Mr. Blachar will serve as

President of the Company until assuming his role as Chief Executive Officer on

July 1, 2020. Mr. Ginzburg currently serves as Executive Vice President and

Chief Financial Officer of Delek US Holdings, Inc. (NYSE: DK) and Delek

Logistics Partners, LP (NYSE: DKL), and has over 15 years of experience in the

energy industry. In his financial positions, Mr. Ginzburg supervised teams of

senior financial professionals and has significant experience in all aspects

    of corporate finance, financial planning, tax, accounting and investor
    relations.

• As of February 2020, the reconstruction efforts at Puna continue. Building

permits that are required for the construction and operation of the substation

were delayed and were received in mid February 2020. HELCO continue with their

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.




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• In January 2020, we signed two similar PPAs with Silicon Valley Clean Energy

(SVCE) and Monterey Bay Community Power (MBCP). Under the PPAs, SVCE and MBCP

will each purchase 7 MW (for a total of 14 MW) of power generated by the

expected 30 MW Casa Diablo-IV (CD4) geothermal project located in Mammoth

Lakes, California that is under construction. The PPAs are for a term of 10

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

California Public Power Authority, which was signed in early 2019. The CD4

power plant is expected to be on-line by the end of 2021, will be the first

geothermal power plant built within the California Independent System Operator

(CAISO) balancing authority in the last 30 years and will be the first in

Ormat's portfolio that will sell its output to a Community Choice Aggregator.

• In December 2019, PGV and Hawaiian Electric's Hawaii Electric Light subsidiary

reached an agreement on an amended and restated PPA for dispatchable

geothermal power sold from Ormat's Puna complex, located on the Big Island of

Hawaii. The new PPA extends the term until 2052 with an increased contract

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 $70

per MWh for all energy purchased during any contract year up to 227,000 MWh

and $40 per MWh above 227,000 MWh. In addition, annual capacity payments under

the contract are approximately $19.5 million. The amended PPA was filed with

the Public Utilities Commission (PUC) on December 31, 2019 for its review and

approval, which is anticipated during 2020. We are planning to replace ten

25-year-old steam units with two new Ormat binary units and to upgrade the

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.




  • In December 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 U.S. support for the geothermal industry.

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 November 2019, we announced that Mr. Doron Blachar, our CFO, was appointed

to serve as our President, effective immediately. As President, Mr. Blachar

assists our CEO, Isaac Angel, with the Company's strategic direction and

operational management until he assumes Mr. Angel's position in July 1, 2020.

• In August 2019, we announced that one of our wholly owned subsidiaries that

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 $59.3 million and

for which it will pay additional annual installments that are expected to

amount to a total of approximately $9 million and can reach up to $22 million

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 July 2019, we commenced commercial operation of our first-ever geothermal

and solar hybrid project, a 7MW AC solar expansion of our Tungsten Mountain

geothermal project in Churchill County, Nevada. The electricity generated from

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 Southern California Public Power Authority

("SCPPA") portfolio contract. SCPPA and the Los Angeles Department of Water

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 for Los Angeles.




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• In July 2019 we announced that we signed and closed a set of agreements to

acquire 49% of the Ijen geothermal project company, which is holding a PPA and

geothermal license to develop the Ijen project in East Java, Indonesia, from

a Medco Power subsidiary. Under the terms of the agreements, Ormat acquired

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 Medco Power retains 51% ownership of Our

company. Ormat and Medco will develop the project jointly.

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 May 2019, we completed the drawdown of $23.5 million under a non-recourse

loan agreement with Siemens Financial Services for the financing of Plumsted

and Stryker, two 20 MW battery energy storage projects located in New Jersey.

The loan bears interest of three months U.S. LIBOR plus 3.5% margin and its

    final maturity date is May 30, 2026.

• In March 2019, we entered into a first addendum ("First Addendum") to the

Migdal Loan Agreement with several entities within the Migdal Group, a leading

Israeli insurance company and institutional investor in Israel. The First

Addendum provides us with an additional loan by the lenders in an aggregate

principal amount of $50.0 million that will be repaid in 15 semi-annual

payments of $2.1 million each, commencing on September 15, 2021, with a final

payment of $18.5 million on March 15, 2029. The $50.0 million loan bears

    interest at a fixed rate of 4.6% per annum, payable semi-annually.




  • In March 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 Mammoth Lakes, California. SCPPA will resell the output to the City

of Colton. The CD4 power plant will be the first geothermal power plant built

within the California Independent System Operator ("CAISO") balancing

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 $68 per MWh. We are in

negotiations to sell the balance of 14MW to other offtakers or at the spot

    market.

• In January 2019, we entered into a $41.5 million subordinated loan agreement

with Deutsche Investitions-und Entwicklungsgesellschaft mbH ("DEG") and on

February 28, 2019, we completed a drawdown of the full loan amount, with a

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 June 21, 2028. Proceeds of the loan

    were used to refinance upgrades to Plant 1 of the Olkaria 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 the United States as costs for electricity generated

from renewable resources have become more competitive. Much of this is

attributable to legislative and regulatory requirements and incentives, such

as state RPS and federal tax credits such as PTCs or ITCs (which are discussed

in more detail in the section entitled "Government Grants and Tax Benefits"

below). We believe that future demand for energy generated from geothermal and

other renewable resources in the United States will be driven primarily by

further commitment to, and implementation of, state RPS and greenhouse gas

    reduction initiatives.




  ? 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.




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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 New Zealand, Turkey, the

U.S., Asia Pacific and Central and South America. We have experienced

increased competition from binary power plant equipment suppliers including

the major steam turbine manufacturers. While we believe that we have a

distinct competitive advantage based on our technology, accumulated experience

and current worldwide share of installed binary generation capacity, an

increase in competition may impact our ability to secure new purchase orders

from potential customers. The increased competition may also leads to further

reductions in the prices that we are able to charge for our binary equipment,

as we recently experienced in Turkey, which in turn reduces our profitability.

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, $86.6 and $87.0 per MWh

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. Turkey is ranked fourth globally with an installed geothermal

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 U.S. sanctions on the Turkish economy and the straining of U.S.-Turkey

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 December 31, 2019, we derived 12% and 47% of our

    Total revenues and Product revenues, respectively, from our Turkish
    operations. We are monitoring any change in the political and business
    environments that may affect our future business and operations in the
    country.

? Ormat established a manufacturing facility in Turkey in order to locally

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 Turkey entitles such

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 Turkey may not be issued a

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 Kenya, we received three letters of assessment and preliminary findings

from the KRA in relation to its review of the 2013 to 2017 tax years in which

the KRA demanded we pay approximately $228.0 million including interest and

penalties ($177.0 million principal). We are currently in different stages of

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 September 28,

2017 and December 31, 2022 to be deducted immediately. However, the tax equity

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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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 ended December 31,
2019 were derived from PPAs with fixed price components, we have variable price
PPAs in California and Hawaii. 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 Ended December 31,                     

Year Ended December 31,

                           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 Ended December 31,                      

Year Ended December 31,

                          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 %




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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 our U.S. operations in each of those years. A substantial
portion of international revenues came from Kenya and Turkey and, to a lesser
extent, from Honduras, Guadeloupe, Guatemala and other countries. Our operations
in Kenya contributed disproportionately to gross profit and net income. The
contribution to combined pre-tax income of our domestic and foreign operations
within our Electricity segment and Product segment differ in a number of ways.



Electricity Segment. Our Electricity segment domestic revenues were
approximately 62%, 60% and 64% of our total Electricity segment for the years
ended December 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, like Kenya, Guatemala, Honduras and
Guadeloupe, which favorably impact payroll and maintenance expenses among other
items. They are also newer than most of our domestic power plants and therefore
tend to have lower maintenance costs and higher availability factors than our
domestic power plants. Consequently, in 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 ended December 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 the Heber
2 power plant in the Heber Complex, the Mammoth Complex and the North Brawley
power plant in California, the Raft River power plant in Idaho and the Neal Hot
Springs power plant in Oregon, 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 our California power plants, our principal cost of revenues also
includes transmission charges and scheduling charges. In some of our Nevada
power plants we also incur transmission and wheeling charges. Some of these
expenses, such as parts, third-party services and major maintenance, are not
incurred on a regular basis. This results in fluctuations in our expenses and
our results of operations for individual power plants from quarter to quarter.
Payments made to government agencies and private entities on account of site
leases where power plants are located are included in cost of revenues. Royalty
payments, included in cost of revenues, are made as compensation for the right
to use certain geothermal resources and are paid as a percentage of the revenues
derived from the associated geothermal rights. Royalties constituted
approximately 4.1% and 4.2% of Electricity segment revenues for the years ended
December 31, 2019 and 2018, respectively.



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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.




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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 at December 31, 2019 and 2018, respectively. Included in these
amounts at December 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 ended December 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.



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• Goodwill. Goodwill represents the excess of the fair value of consideration

transferred in the business combination transactions over the fair value of

tangible and intangible assets acquired, net of the fair value of liabilities

assumed and the fair value of any noncontrolling interest in the acquisitions.

Goodwill is not amortized but rather subject to a periodic impairment testing

on an annual basis (on December 31 of each year) or if an event occurs or

circumstances change that would more likely than not reduce the fair value of

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 January 2017, the

FASB issued ASU 2017-04, Intangibles - Goodwill and Other (Topic 350), which

was adopted by us in 2018, under which step two of the goodwill impairment

test was eliminated. Step two measured a goodwill impairment test by comparing

the implied fair value of reporting unit's goodwill with the carrying amount

of that goodwill. Under ASU 2017-04, Intangibles - Goodwill and Other, an

entity should recognize an impairment charge for the amount by which the

carrying amount of the reporting unit exceeds its fair value as calculated

under step one described above. However, the loss recognized should not exceed

    the total amount of goodwill allocated to that reporting unit

• 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 our U.S. deferred tax assets. In the
future, if there is sufficient evidence that we will be able to generate
sufficient future taxable income in the United States, we may be required to
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.



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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




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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 %




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Comparison of the Year Ended December 31, 2019 and the Year Ended December 31, 2018

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 ended December 31,
2019 were $540.3 million, compared to $509.9 million for the year ended December
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 our McGinness Hills Complex in Nevada, effective December 2018,
which generated total complex revenues of $96.9 million for the year ended
December 31, 2019 compared to $65.1 million for the year ended December 31,
2018; (ii) the consolidation of USG which was acquired on April 24, 2018, and
contributed $35.6 million for the year ended December 31, 2019, compared to
$21.4 million for the year ended December 31, 2018; and (iii) the commencement
of commercial operation of our Plant 1 expansion project in the Olkaria III
Complex in Kenya, effective June 2018. The increase was partially offset by (i)
the shutdown of our Puna power plant following the Kilauea volcanic eruption on
May 3, 2018 which resulted in a reduction of $15.5 million in revenues compared
to the year ended December 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 ended December 31, 2018 to 6,238,272 MWh in the year ended December 31,
2019, primarily because of an increase in generation due to the commencement of
commercial operation of the third phase of our McGinness Hills Complex in
Nevada, Plant 1 expansion in Kenya 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 ended December 31,
2019 were $191.0 million, compared to $201.7 million for the year ended December
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 in
Turkey in 2018, which accounted for $91.1 in Product segment revenues in the
year ended December 31, 2018, which were partially offset by (i) the start of
four new projects in Turkey, New Zealand and Chile in 2019, which provided $90.3
million in revenue for the year ended December 31, 2019; and (ii) other projects
mainly in Turkey and the U.S., which were started in 2018, and provided $72.2
million in revenue for the year ended December 31, 2019 compared to $90.0
million for the year ended December 31, 2018.





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Energy Storage and Management Services Segment

Revenues attributable to our Energy Storage and Management Services segment for
the year ended December 31, 2019 were $14.7 million compared to $7.6 million for
the year ended December 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
ended December 31, 2019 was $312.8 million, compared to $298.3 million for the
year ended December 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 our
McGinness Hills Complex plant in Nevada, effective December 2018 and (ii)
commencement of commercial operation of our Plant 1 expansion project in the
Olkaria III Complex in Kenya, effective June 2018. As a percentage of total
Electricity revenues, the total cost of revenues attributable to our Electricity
segment for the year ended December 31, 2019 was 57.9%, compared to 58.5% for
the year ended December 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 our McGinness Hills Complex and from our assets that were
acquired from USG and contributed partially in 2018, partly offset by the Puna
power plant in Hawaii, for which we recorded cost of revenues with no associated
revenues due to the shut-down of the power plant following the Kilauea volcanic
eruption in May 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 ended
December 31, 2019 was $146.0 million, compared to $140.7 million for the year
ended December 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 in Turkey that had an impact on revenue and
related cost of revenues in the year ended December 31, 2019. As a percentage of
total Product segment revenues, our total cost of revenues attributable to our
Product segment for the year ended December 31, 2019 was 76.4%, compared to
69.7% for the year ended December 31, 2018.

Energy Storage and Management Services Segment

Cost of revenues attributable to our Energy Storage and Management Services
segment for the year ended December 31, 2019 were $17.9 million as compared to
$9.9 million in the year ended December 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 December 31, 2019 were $4.6 million, compared to $4.2 million for the year ended December 31, 2018.

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Selling and Marketing Expenses

Selling and marketing expenses for the year ended December 31, 2019 were $15.0
million, compared to $19.8 million for the year ended December 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 ended December 31,
2018. Selling and marketing expenses constituted 2.0% of total revenues for the
year ended December 31, 2019, compared to 2.1%, excluding the termination fee,
for the year ended December 31, 2018.

General and Administrative Expenses

General and administrative expenses for the year ended December 31, 2019 were
$55.8 million, compared to $47.8 million for the year ended December 31, 2018.
The increase was primarily attributable to a $10.3 million income adjustment in
the year ended December 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 ended December 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 ended December 31, 2019 constituted 7.5% of total revenues for such
period, compared to 8.1%, excluding the earn out adjustment, for the year ended
December 31, 2018.



Goodwill Impairment Charge

There was no goodwill impairment charge for the year ended December 31, 2019. Goodwill impairment charge for the year ended December 31, 2018 was $13.5 million related to the acquisition of our Viridity business.

Operating Income



Operating income for the year ended December 31, 2019 was $193.8 million,
compared to $185.1 million for the year ended December 31, 2018, representing a
4.7% increase from the prior period. Operating income attributable to our
Electricity segment for the year ended December 31, 2019 was $177.2 million
compared to $155.5 million for the year ended December 31, 2018. Operating
income attributable to our Product segment for the year ended December 31, 2019
was $23.2 million, compared to $38.1 million for the year ended December 31,
2018. Operating loss attributable to our Energy Storage and Management Services
segment for the year ended December 31, 2019 was $6.6 million compared to $8.5
million for the year ended December 31, 2018.



Interest Expense, Net



Interest expense, net, for the year ended December 31, 2019 was $80.4 million,
compared to $70.9 million for the year ended December 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 on March 22, 2018 and March 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 on October 29, 2018 from OPIC for financing the
Honduras power plant; and (iv) $41.5 million of proceeds from a full recourse
loan received on January 4, 2019 from DEG for financing the Kenya 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 ended December
31, 2019 were $0.6 million, compared to losses of $4.8 million for the year
ended December 31, 2018. Derivatives and foreign currency transaction gains for
the year ended December 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
ended December 31, 2018 were primarily attributable to losses from foreign
currency forward contracts, which were not accounted for as hedge transactions.



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Income Attributable to Sale of Tax Benefits

Income attributable to the sale of tax benefits for the year ended December 31,
2019 was $20.9 million, compared to $19.0 million for the year ended December
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 ended December 31, 2019 was $0.9
million, compared to other non-operating expense, net of $7.8 million for the
year ended December 31, 2018. Other non-operating income for the year ended
December 31, 2019 mainly includes an income of $1.0 million from the sale of
PG&E receivables relating to the January 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 ended December 31, 2018 mainly includes
income of a $7.2 million insurance settlement of our Puna power plant rig which
was damaged by the Kilauea 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 ended December 31, 2019  was $137.3 million, compared to $137.2
million for the year ended December 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 ended December 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 ended December 31, 2018. Our effective tax rate for the year ended
December 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 in the United States. Our
aggregate effective tax rate for the year ended December 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.



On December 22, 2017, the U.S. government signed into law the Tax Act. The Tax
Act makes significant changes to the U.S. tax code, including, but not limited
to, (1) reducing the U.S. federal corporate income tax rate from 35 percent to
21 percent; (2) the transition of U.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
of December 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 after December 31, 2017.

Equity in Earnings (losses) of investees, net

Equity in earnings (losses) of investees, net in the year ended December 31,
2019 was $1.9 million, compared to $7.7 million in the year ended December 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.



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Net Income



Net income for the year ended December 31, 2019 was $93.5 million, compared to
$110.1 million for the year ended December 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 ended
December 31, 2019 was $88.1 million, compared to $98.0 million for the year
ended December 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 in
Hawaii, all as discussed above.

Comparison of the year ended December 31, 2018 and the year ended December 31, 2017

Total Revenues



Total revenues for the year ended December 31, 2018 were $719.3 million,
compared to $692.8 million for the year ended December 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 ended December 31,
2018, were $509.9 million, compared to $465.6 million for the year ended
December 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 in Honduras, effective September 2017,
with revenues of $34.4 million for the year ended December 31, 2018 compared to
$10.0 million for the year ended December 31, 2017; (ii) the consolidation of
USG which was acquired on April 24, 2018, with revenues of $21.4 million for the
year ended December 31, 2018; (iii) the commencement of commercial operation of
our Tungsten Mountain power plant in Nevada, effective December 2017, with
revenues of $15.7 million for the year ended December 31, 2018 compared to $2.2
million for the year ended December 31, 2017; (iv) the commencement of
commercial operation of our Plant 1 expansion project in the Olkaria III Complex
in Kenya, effective June 2018; and (v) higher energy rates under the new Ormesa
1 PPA commencing in December 2017. The increase was partially offset due to (i)
a decrease in revenues at our Puna power plant that was shut down immediately
following the Kilauea volcanic eruption on May 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 ended December 31, 2017 to 5,857,963 MWh in the year ended December 31,
2018, primarily because of an increase in generation due to the commencement of
commercial operations of our Platanares power plant in Honduras, Tungsten
Mountain power plant in Nevada, and Plant 1 expansion in Kenya 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.



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Product Segment



Revenues attributable to our Product segment for the year ended December 31,
2018 were $201.7 million, compared to $224.5 million for the year ended December
31, 2017, representing a 10.1% decrease from the prior period. We recognized
approximately $31.4 million and $23.1 million in revenues, from the New Zealand
and China projects, respectively, in the year ended December 31, 2017, compared
to $8.8 million and $0.5 million in the year ended December 31, 2018. The
projects were completed in 2018. The decrease in our Product segment revenues
was also attributable to other projects in Turkey, which were completed in 2017,
and by a decrease in revenues as a result of completion of our contracts for
geothermal projects in Chile and the Sarulla project. The decrease was partially
offset by the start of new projects in Turkey, which provided $154.3 million in
revenue recognized during the year ended December 31, 2018.

Energy Storage and Management Services Segment

Revenues attributable to our Energy Storage and Management Services segment for
the year ended December 31, 2018 were $7.6 million compared to $2.7 million for
the year ended December 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 of Viridity Energy,
Inc. on March 15, 2017.



Total Cost of Revenues



Total cost of revenues for the year ended December 31, 2018 was $448.8 million,
compared to $424.4 million for the year ended December 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 ended December 31, 2018 increased to
62.4%, compared to 61.3% for the year ended December 31, 2017.



Electricity Segment



Total cost of revenues attributable to our Electricity segment for the year
ended December 31, 2018 was $298.3 million, compared to $266.8 million for the
year ended December 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 in
Honduras, effective September 2017, our Tungsten Mountain power plant in Nevada,
effective December 2017 and commencement of commercial operation of our Plant 1
expansion project in the Olkaria III Complex in Kenya, effective June 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 on April 24, 2018. As a percentage of
total Electricity segment revenues, the total cost of revenues attributable to
our Electricity segment for the year ended December 31, 2018 was 58.5%, compared
to 57.3% for the year ended December 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 ended
December 31, 2018 was $140.7 million, compared to $152.1 million for the year
ended December 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
ended December 31, 2018 was 69.7%, compared to 67.8% for the year ended December
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 ended December 31, 2018 were $9.9 million, compared to $5.4
million for the year ended December 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.



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Research and Development Expenses

Research and development expenses for the year ended December 31, 2018 were $4.2 million, compared to $3.2 million for the year ended December 31, 2017.

Selling and Marketing Expenses

Selling and marketing expenses for the year ended December 31, 2018 were $19.8
million, compared to $15.6 million for the year ended December 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 ended December 31, 2018, excluding
the termination fee, constituted 2.1% of total revenues for such year, compared
to 2.3% for the year ended December 31, 2017.

General and Administrative Expenses

General and administrative expenses for the year ended December 31, 2018 were
$47.8 million, compared to $42.9 million for the year ended December 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 on March
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 ended December 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

Goodwill impairment charge for the year ended December 31, 2018 was $13.5 million related to the acquisition of our Viridity business. There was no goodwill impairment charge for the year ended December 31, 2017.

Write-off of Unsuccessful Exploration Activities

Write-off of unsuccessful exploration activities for the year ended December 31,
2018 was $0.1 million, compared to $1.8 million for the year ended December 31,
2017. The write-off of unsuccessful exploration activities for the year ended
December 31, 2017, included costs related to the Glass Buttes site in Oregon,
which we determined in the fourth quarter of 2017, would not support commercial
operations.



Operating Income



Operating income for the year ended December 31, 2018 was $185.1 million,
compared to $205.0 million for the year ended December 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 ended December 31, 2018 was
$155.5 million, compared to $157.6 million for the year ended December 31, 2017.
Operating income attributable to our Product segment for the year ended December
31, 2018 was $38.1 million, compared to $50.5 million for the year ended
December 31, 2017. Operating loss attributable to our Energy Storage and
Management Services segment for the year ended December 31, 2018 was $8.5
million compared to a loss of $3.1 million for the year ended December 31, 2017.



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Interest Expense, Net



Interest expense, net, for the year ended December 31, 2018 was $70.9 million,
compared to $54.1 million for the year ended December 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 on March 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 on October 29,
2018 from OPIC for financing the Honduras 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 ended December
31, 2018 were $4.8 million, compared to gains of $2.7 million for the year ended
December 31, 2017. Derivatives and foreign currency transaction losses for the
year ended December 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 ended December
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 ended December 31, 2018
was $19.0 million, compared to $17.9 million for the year ended December 31,
2017. This income primarily represents the value of PTCs and taxable income or
loss generated by Opal Geo and Tungsten allocated to the investor in the year
ended December 31, 2018 compared to the value of PTCs and taxable income or loss
generated by Opal Geo allocated to the investors in the year ended December 31,
2017.

Other Non-Operating Income (loss)

Other non-operating income, net for the year ended December 31, 2018 was $7.8
million, compared to Other non-operating expense, net of $1.7 million for the
year ended December 31, 2017. Other non-operating expense, net for the year
ended December 31, 2018 includes an income of $7.2 million insurance settlement
of our Puna power plant rig which was damaged by the Kilauea volcanic eruption.
Other non-operating expense, net for the year ended December 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 ended December 31, 2018 was $137.2 million, compared to $170.7
million for the year ended December 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 ended
December 31, 2018, as described above.



 Income Taxes



Income tax provision for the year ended December 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 ended December 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 of U.S. federal tax reform that resulted in a
one-time tax impact for the year ended December 31, 2017. Our effective tax rate
for the years ended December 31, 2018 and 2017, was 25.3% and 12.7%,
respectively. Our effective tax rate at December 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 in Kenya of 37.5% and Guadeloupe of
33.33% partially offset by a lower tax rate in Israel 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).



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For the years ended December 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) and U.S.
deferred tax assets related to state net operating loss (NOL) carryforwards. As
of December 31, 2018, we had U.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 in the 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 the U.S. deferred tax assets as of
December 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.



On December 22, 2017, the U.S. government signed into law the Tax Act.  The Tax
Act makes significant changes to the U.S. tax code, including, but not limited
to, (1) reducing the U.S. federal corporate income tax rate from 35 percent to
21 percent; (2) the transition of U.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
of December 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 after December 31, 2017.



We applied the guidance of SAB 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 at December 31, 2017. In addition, at
December 31, 2017, we recorded a provisional benefit of $22.6 million relating
to the remeasurement of deferred taxes from 35% to 21%.



As of December 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 by
Treasury applies regardless of whether the interest payment is made to a U.S. or
foreign person, whether the interest recipient is related, or whether the
interest recipient is exempt from U.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 ended December 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 in United States taxable income as a current period expense when
incurred or reflect such portion of the future GILTI inclusions in United 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 future
U.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 by Treasury.
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.



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Equity in Earnings (losses) of Investees, Net

Equity in earnings (losses) of investees, net in the year ended December 31,
2018 was a profit of $7.7 million, compared to a loss of $2.0 million in the
year ended December 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 from May 2018.



Net Income



Net income for the year ended December 31, 2018 was $110.1 million, compared to
$147.1 million for the year ended December 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 ended
December 31, 2018 was $98.0 million, compared to $132.4 million for the year
ended December 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 in
Hawaii, 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 of December 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 December 31, 2019, $213.8 million in the aggregate was outstanding under credit agreements with several banks as detailed below under "Credit Agreements".

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



During 2019, we have revised our assertion to no longer indefinitely reinvest
foreign funds held by our foreign subsidiaries, with the exception of a certain
balance held in Israel 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.



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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 EUR 8.0 million

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 of December 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 ended December 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.



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Future minimum payments



Future minimum payments under long-term obligations, excluding revolving credit
lines with commercial banks, as of December 31, 2019, are detailed under the
caption Contractual Obligations and Commercial Commitments, below.

Puna Power Plant Lease Transactions

In May 2005, our Hawaiian subsidiary, PGV, entered into lease transactions involving the original geothermal power plant of the Puna Complex located on the Big Island (the Puna Power Plant).

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 of
December 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 of December 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 $ 236,493 $ 145,822

    $   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 )




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For the Year Ended December 31, 2019

Net cash provided by operating activities for the year ended December 31, 2019
was $236.5 million, compared to $145.8 million for the year ended December 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 ended December
31, 2019, compared to a decrease of $56.7 million in the year ended December 31,
2018, driven by: (i) a withholding tax payment of approximately $14 million in
the year ended December 31, 2019 compared to $44 million in the year ended
December 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 ended December 31, 2019 compared to $29.9 million in the year ended
December 31, 2018 because of timing of collections from our customers.



Net cash used in investing activities for the year ended December 31, 2019 was
$254.5 million, compared to $342.4 million for the year ended December 31, 2018.
The principal factors that affected our net cash used in investing activities
during the year ended December 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 ended December 31, 2019 was
$5.8 million, compared to $251.1 million provided by financing activities for
the year ended December 31, 2018. The principal factors that affected the net
cash used in financing activities during the year ended December 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 our Olkaria 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 our Guadeloupe 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 December 31, 2018

Net cash provided by operating activities for the year ended December 31, 2018
was $145.8 million, compared to $245.6 million for the year ended December 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 ended
December 31, 2018, compared to an increase of $51.6 million in the year ended
December 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 ended December 31, 2018 was
$342.4 million, compared to $345.5 million for the year ended December 31, 2017.
The principal factors that affected our net cash used in investing activities
during the year ended December 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 ended December 31, 2018 was
$251.1 million, compared to $67.9 million provided by financing activities for
the year ended December 31, 2017. The principal factors that affected the net
cash provided by financing activities during the year ended December 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.



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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 in the United States, or U.S. GAAP, and should not be considered as an
alternative to cash flow from operating activities or as a measure of liquidity
or an alternative to net earnings as indicators of our operating performance or
any other measures of performance derived in accordance with U.S. GAAP. 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 December 31, 2019 was $384.3 million, compared to $368.0 million for the year ended December 31, 2018 and $343.8 million for the year ended December 31, 2017.

The following table reconciles net income to EBITDA and adjusted EBITDA for the years ended December 31, 2019, 2018 and 2017:

                                                         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 $1.2 million for the year ended December 31, 2019 is $385.5 million.

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.



On May 2014, the Sarulla consortium ("SOL") closed $1,170 million in financing.
As of December 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.



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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 of December 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 $332 million.

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 the Puna Complex and
the between 30 MW and 40 MW PPAs in the aggregate for the Heber 2 power plant in
the Heber Complex and the G2 power plant in the Mammoth Complex) have fixed or
escalating rate provisions that limit our exposure to changes in electricity
prices. The energy payments under the PPAs of the Heber 2 power plant in the
Heber Complex and the G2 power plant in Mammoth Complex are determined by
reference to the relevant power purchaser's SRAC. A decline in the price of
natural gas will result in a decrease in the incremental cost that the power
purchaser avoids by not generating its electrical energy needs from natural gas,
or by reducing the price of purchasing its electrical energy needs from natural
gas power plants, which in turn will reduce the energy payments that we may
charge under the relevant PPA for these power plants. The Puna Complex is
currently benefiting from energy prices which are higher than the floor under
the 25 MW PPA for the Puna Complex as a result of the high fuel costs that
impact HELCO's avoided costs.



As of December 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 of December 31, 2019, $47.9 million of our long-term
debt remained subject to some interest rate risk.



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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 Standard & Poor's Ratings Services.

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 the U.S. dollar versus the NIS in Israel and KES in Kenya. Risks
attributable to fluctuations in currency exchange rates can arise when we or any
of our foreign subsidiaries borrow funds or incur operating or other expenses in
one type of currency but receive revenues in another. In such cases, an adverse
change in exchange rates can reduce such subsidiary's ability to meet its debt
service obligations, reduce the amount of cash and income we receive from such
foreign subsidiary, or increase such subsidiary's overall expenses. In Kenya,
the tax asset is recorded in KES similar to the tax liability, however any
change in the exchange rate in the KES versus the USD has an impact on our
financial results. Risks attributable to fluctuations in foreign currency
exchange rates can also arise when the currency denomination of a particular
contract is not the U.S. dollar. Substantially all of our PPAs in the
international markets are either U.S. dollar-denominated or linked to the U.S.
dollar except for our operations on Guadeloupe, where we own and operate the
Boulliante power plant which sells its power under a Euro-denominated PPA with
Électricité de France S.A. Our construction contracts from time to time
contemplate costs which are incurred in local currencies. The way we often
mitigate such risk is to receive part of the proceeds from the contract in the
currency in which the expenses are incurred. Currently, we have forward
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 ended December 31, 2019, our exchange rate exposure in Kenya
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 at December 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 December 31, 2019 and 2018 are presented below:

                      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




In July 2019, the United Kingdom's Financial Conduct Authority, which regulates
LIBOR (London Interbank Offered Rate), announced that it intends to phase out
LIBOR by the end of 2021. It is unclear whether or not LIBOR will cease to exist
at that time and/or whether new methods of calculating LIBOR will be established
such that it will continue to exist after 2021. The U.S. Federal Reserve, in
conjunction with the Alternative Reference Rates Committee, a steering committee
comprised of large U.S. financial institutions, is considering replacing U.S.
dollar LIBOR with a new SOFR (Secured Overnight Financing Rate) index calculated
by short-term repurchase agreements, backed by Treasury securities.



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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 our U.S. PPAs, including the
SCPPA Portfolio PPA, are directly linked to the CPI. Inflation may directly
impact an expense we incur for the operation of our projects, thereby increasing
our overall operating costs and reducing our profit and gross margin. The
negative impact of inflation would be partially offset by price adjustments
built into some of our PPAs that could be triggered upon such occurrences. The
energy payments pursuant to our PPAs for some of our power plants such as the
Brady power plant, the Steamboat 2 and 3 power plants and the McGinness Complex,
increase every year through the end of the relevant terms of such agreements,
although such increases are not directly linked to the CPI or any other
inflationary index. Lease payments are generally fixed, while royalty payments
are generally calculated as a percentage of revenues and therefore are not
significantly impacted by inflation. In our Product segment, inflation may
directly impact fixed and variable costs incurred in the construction of our
power plants, thereby increasing our operating costs in the Product segment. We
are more likely to be able to offset all or part of this inflationary impact
through our project pricing. With respect to power plants that we build for our
own electricity production, inflationary pricing may impact our operating costs
which may be partially offset in the pricing of the new long-term PPAs that we
negotiate.

Contractual Obligations and Commercial Commitments

The following tables set forth our material contractual obligations as of December 31, 2019 (in thousands):

                                                                 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 December 31,

2019, total obligations related to such supplier agreements were

approximately $185.0 million (approximately $59.5 million of which relate to

    construction-in-process). All such obligations are payable in 2020.




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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 and Nevada 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 and Nevada Power Company accounted for 17.1%, 16.1%
and 18.1% of our total revenues for the three years ended December 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 December 31, 2019, 2018 and 2017, respectively.

SCPPA accounted for 17.9%, 15.2% and 10.1% of our total revenues for the three years ended December 31, 2019, 2018 and 2017, respectively.

We have historically been able to collect on substantially all of our receivable
balances. As of December 31, 2019, the amount overdue from KPLC in Kenya 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 from
September 30, 2019. In Honduras, we began collecting current charges from ENEE
in May 2019; however, as of December 31, 2019, the amount overdue relating to
the period from October 2018 to April 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 U.S. federal government encourages production of electricity from geothermal resources or solar energy through certain tax subsidies:

• 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

2.5 cents per kWh, is adjusted annually for inflation and may be claimed for

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

December 2019 provides that any qualifying project that starts construction by

December 31, 2020 would be eligible for PTC. The qualifying project must

ordinarily be placed in service within four years after the end of the year in

which construction started or show continued construction to qualify for PTC.

The PTC is not available for power produced from geothermal resources for

    projects that started construction on or after January 1, 2021.

• ITC - the ITC rules have been amended a number of times. A qualified new

geothermal power plant in the United States that starts construction by the

end of 2020 would be eligible to claim an ITC of 30% of the project cost. New

solar projects that were under construction by December 2019 will qualify for

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 December 31, 2023 to qualify for the ITC at these rates.

solar projects placed in service after December 31, 2023 will only qualify for

a 10% ITC. Under current tax rules, any unused tax credit has a one-year carry

    back and a twenty-year carry forward.




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• On December 22, 2017, the U.S. President signed into law the Tax Act, which

made changes that have some impact on the renewable energy industry. Some of

the key changes are as follows:

• The U.S. corporate income tax rate was reduced from 35% to 21% beginning in

2018.

• Bonus depreciation was increased from 40% expensing of qualified projects in

year one to 100% beginning in on September 27, 2017. The 100% expensing is

    valid through 2022 and then declines through 2026.


  • The BEAT provision is a new tax intended to apply to companies that

significantly reduce their U.S. tax liability by making cross-border payments

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 after September 27, 2017, could qualify for a
100% bonus depreciation with respect to its qualifying assets. After applying
any depreciation bonus that is available, we can depreciate the remainder of our
tax basis in the plant, if any, mostly over five years on an accelerated basis,
meaning that more of the cost may be deducted in the first few years than during
the remainder of the depreciation period. We will continue to analyze this new
provision under the Act and determine if an election is appropriate as it
relates to our business needs.



Ormat Systems received "Benefited Enterprise" status under Israel's Law for
Encouragement of Capital Investments, 1959 (the Investment Law), with respect to
two of its investment programs through 2011. In January 2011, new legislation
amending the Investment Law was enacted. Under the new legislation, a uniform
rate of corporate tax will apply to all qualified income of certain industrial
companies, as opposed to the previous law's incentives that are limited to
income from a "Benefited Enterprise" during their benefits period. As a result,
we now pay a uniform corporate tax rate of 16% with respect to that qualified
income.



Kenya tax audit

The Company received three letters from the Kenya Revenue Authority ("KRA") relating to certain findings in respect of its review of tax years 2013 to 2017 as described below:

The first Letter of Preliminary Findings was received in March 2019, which was
followed by a Notice of Assessment during June 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.
In July 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 in July 2019, which relates to
findings from the KRA's audit review for tax years 2013 to 2017. In August 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. In December 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. In January 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 in December 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. In January
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 of December 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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