UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
☑ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, | |
Or
☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number: 001-32347
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ORMAT TECHNOLOGIES, INC.
(Exact name of registrant as specified in its charter)
DELAWARE | 88-0326081 |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification Number) |
6225 Neil Road, Reno, Nevada 89511-1136
(Address of principal executive offices, including zip code)
Registrant’s telephone number, including area code:
(775) 356-9029
(Registrant’s telephone number, including area code)
Securities Registered Pursuant to Section 12(b) of the Act:
Title of Each Class | Name of Each Exchange on Which Registered |
Common Stock $0.001 Par Value | New York Stock Exchange |
Securities Registered Pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☑
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ☐ No ☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑ No ☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ☑ | Accelerated filer ☐ | Non-accelerated filer ☐ | Smaller reporting company ☐ |
(Do not check if a smaller reporting company) | Emerging growth company ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑
As of June 30, 2016,2017, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $1,418,095,165$2,315,466,032 based on the closing price as reported on the New York Stock Exchange. Indicate the number of shares outstanding of each of the registrant’s classes of common stock as of the latest practicable date: As of February 27, 2017,23, 2018, the number of outstanding shares of common stock, par value $0.001 per share was 49,667,340.50,609,051.
Documents incorporated by reference: Part III (Items 10, 11, 12, 13 and 14) incorporates by reference portions of the Registrant’s Proxy Statement for its Annual Meeting of Stockholders, which will be filed not later than 120 days after December 31, 2016.2017.
ORMAT TECHNOLOGIES, INC.
FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 20162017
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ITEM 1. | 7 | |
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ITEM 3. |
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ITEM 4. |
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ITEM 5. |
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ITEM 6. |
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ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
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ITEM 7A. |
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ITEM 8. |
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ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
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ITEM 9A. |
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ITEM 9B. |
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ITEM 10. |
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ITEM 11. |
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ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
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ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
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ITEM 14. |
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ITEM 15. |
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Glossary of Terms
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
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Term | Definition |
Amatitlan Loan | $42,000,000 in initial aggregate principal amount borrowed by our subsidiary Ortitlan Limitada from Banco Industrial S.A. and Westrust Bank (International) Limited. |
AMM | Administrador del Mercado Mayorista (administrator of the wholesale market — Guatemala) |
ARRA | American Recovery and Reinvestment Act of 2009 |
Auxiliary Power | The power needed to operate a geothermal power plant’s auxiliary equipment such as pumps and cooling towers |
Availability | The ratio of the time a power plant is ready to be in service, or is in service, to the total time interval under consideration, expressed as a percentage, independent of fuel supply (heat or geothermal) or transmission accessibility |
Balance of Plant equipment | Power plant equipment other than the generating units including items such as transformers, valves, interconnection equipment, cooling towers for water cooled power plants, etc. |
BESS | Battery Energy Storage Systems |
BLM | Bureau of Land Management of the U.S. Department of the Interior |
BOT | Build, operate and transfer |
CAGR | Compound annual growth rate |
Capacity | The maximum load that a power plant can carry under existing conditions, less auxiliary power |
Capacity Factor | The ratio of the average load on a generating resource to its generating capacity during a specified period of time, expressed as a percentage |
CARB | California Air Resources Board |
CDC | Caisse des Dépôts et Consignations, a French state-owned financial organization |
CFE | Comision Federal de Electricidad |
C&I | Refers to the Commercial and Industrial sectors, excluding residential |
CNE | National Energy Commission of Honduras |
CNEE | National Electric Energy Commission of Guatemala |
COD | Commercial Operation Date |
Company | Ormat Technologies, Inc., a Delaware corporation, and its consolidated subsidiaries |
COSO | Committee of Sponsoring Organizations of the Treadway Commission |
CPI | Consumer Price Index |
CPUC | California Public Utilities Commission |
Cyrq | Cyrq Energy, Inc. |
DEG | Deutsche Investitions-und Entwicklungsgesellschaft mbH |
DFIs | Development Finance Institutions |
DOE | U.S. Department of Energy |
DOGGR | California Division of Oil, Gas, and Geothermal Resources |
DSCR | Debt Service Coverage Ratio |
DSIRE | Database of State Incentives for Renewables and Efficiency |
EBITDA | Earnings before interest, taxes, depreciation and amortization |
EDF | Electricite de France S.A. |
EGS | Enhanced Geothermal Systems |
EIB | European Investment Bank |
ENEE | Empresa Nacional de Energía Eléctrica |
Enthalpy | The total energy content of a fluid; the heat plus the mechanical energy content of a fluid (such as a geothermal brine), which, for example, can be partially converted to mechanical energy in an Organic Rankine Cycle. |
Term | Definition |
EPA | U.S. Environmental Protection Agency |
EPC | Engineering, procurement and construction |
EPS | Earnings per share |
ERC | Kenyan Energy Regulatory Commission |
ERCOT | Electric Reliability Council of Texas, Inc. |
ESC | Energy Sales Contract |
Exchange Act | U.S. Securities Exchange Act of 1934, as amended |
FASB | Financial Accounting Standards Board |
FERC | U.S. Federal Energy Regulatory Commission |
FIT | Feed-in Tariff |
FPA | U.S. Federal Power Act, as amended |
GAAP | Generally accepted accounting principles |
GCCU | Geothermal Combined Cycle Unit |
GDC | Geothermal Development Company |
GEA | Geothermal Energy Association |
Geothermal Power Plant | The power generation facility and the geothermal field |
Geothermal Steam Act | U.S. Geothermal Steam Act of 1970, as amended |
GHG | Greenhouse gas |
GNP | Gross National Product |
GTM | Green Tech Media |
GW | Giga watt |
GWh | Giga watt hour |
HELCO | Hawaii Electric Light Company |
IFC | International Finance Corporation |
IID | Imperial Irrigation District |
ILA | Israel Land Administration |
INDE | Instituto Nacional de Electrification |
IOUs | investor-owned utilities |
IPPs | Independent Power Producers |
ISO | International Organization for Standardization |
ITC | Investment tax credit |
ITC Cash Grant | Payment for Specified Renewable Energy property in lieu of Tax Credits under Section 1603 of the ARRA |
JBIC | Japan Bank for International Cooperation |
John Hancock | John Hancock Life Insurance Company (U.S.A.) |
JOC | Joined operation contract |
JPM | JPM Capital Corporation |
KenGen | Kenya Electricity Generating Company Ltd. |
Kenyan Energy Act | Kenyan Energy Act, 2006 |
KETRACO | Kenya Electricity Transmission Company Limited |
KLP | Kapoho Land Partnership |
KPLC | Kenya Power and Lighting Co. Ltd. |
kVa | Kilovolt-ampere |
kW | Kilowatt - A unit of electrical power that is equal to 1,000 watts |
kWh | Kilowatt hour(s), a measure of power produced |
LCOE | Levelized Costs of Energy |
LSEs | Load Serving Entities |
Mammoth Pacific | Mammoth-Pacific, L.P. |
MACRS | Modified Accelerated Cost Recovery System |
MEMR | Ministry of Energy and Mineral Resources |
MIGA | Multilateral Investment Guarantee Agency, a member of the World Bank Group |
MW | Megawatt - One MW is equal to 1,000 kW or one million watts |
MWh | Megawatt hour(s), a measure of energy produced |
Term | Definition |
NBPL | Northern Border Pipe Line Company |
NIS | New Israeli Shekel |
NOC | network operations center |
NGI | Natural Gas-California SoCal-NGI Natural Gas price index |
NV Energy | NV Energy, Inc. |
NYSE | New York Stock Exchange |
NYISO | New York Independent System Operator, Inc. |
OEC | Ormat Energy Converter |
OFC | Ormat Funding Corp., a wholly owned subsidiary of the Company |
OFC Senior Secured Notes | $190,000,000 8.25% Senior Secured Notes, due 2020 issued by OFC |
OFC 2 | OFC 2 LLC, a wholly owned subsidiary of the Company |
OFC 2 Senior Secured Notes | Up to $350,000,000 Senior Secured Notes, due 2034 issued by OFC 2 |
OMPC | Ormat Momotombo Power Company, a wholly owned subsidiary of the Company |
Opal Geo | Opal Geo LLC |
OPC | OPC LLC, a consolidated subsidiary of the Company |
OPC Transaction | Financing transaction involving four of our Nevada power plants in which institutional equity investors purchased an interest in our special purpose subsidiary that owns such plants. |
OPIC | Overseas Private Investment Corporation |
OrCal | OrCal Geothermal Inc., a wholly owned subsidiary of the Company |
OrCal Senior Secured Notes | $165,000,000 6.21% Senior Secured Notes, due 2020 issued by OrCal |
Organic Rankine Cycle | A process in which an organic fluid such as a hydrocarbon or fluorocarbon (but not water) is boiled in an evaporator to generate high pressure vapor. The vapor powers a turbine to generate mechanical power. After the expansion in the turbine, the low pressure vapor is cooled and condensed back to liquid in a condenser. A cycle pump is then used to pump the liquid back to the vaporizer to complete the cycle. The cycle is illustrated in the figure below: |
Ormat International | Ormat International Inc., a wholly owned subsidiary of the Company |
Ormat Nevada | Ormat Nevada Inc., a wholly owned subsidiary of the Company |
Ormat Systems | Ormat Systems Ltd., a wholly owned subsidiary of the Company |
ORPD | ORPD LLC, a holding company subsidiary of the Company in which Northleaf Geothermal Holdings, LLC holds a 36.75% equity interest |
ORPD Transaction | Financing transaction involving the Puna complex and Don A. Campbell, OREG 1, OREG 2 and OREG 3 power plants in which Northleaf Geothermal Holdings, LLC purchased an equity interest in our special purpose subsidiary that owns such plants. |
OrPower 4 | OrPower 4 Inc., a wholly owned subsidiary of the Company |
Ortitlan | Ortitlan Limitada, a wholly owned subsidiary of the Company |
ORTP | ORTP, LLC, a consolidated subsidiary of the Company |
Term | Definition |
ORTP Transaction | Financing transaction involving power plants in Nevada and California in which an institutional equity investor purchased an interest in our special purpose subsidiary that owns such plants. |
Orzunil | Orzunil I de Electricidad, Limitada, a wholly owned subsidiary of the Company |
PEC | Portfolio Energy Credits |
PG&E | Pacific Gas and Electric Company |
PGV | Puna Geothermal Venture, a wholly owned subsidiary of the Company |
PJM | PJM Interconnection, L.L.C. |
PLN | PT Perusahaan Listrik Negara |
Power plant equipment | Interconnection equipment, cooling towers for water cooled power plant, etc., including the generating units |
PPA | Power purchase agreement |
ppm | Part per million |
PTC | Production tax credit |
PUA | Israeli Public Utility Authority |
PUCH | Public Utilities Commission of Hawaii |
PUCN | Public Utilities Commission of Nevada |
PUHCA | U.S. Public Utility Holding Company Act of 1935 |
PUHCA 2005 | U.S. Public Utility Holding Company Act of 2005 |
PURPA | U.S. Public Utility Regulatory Policies Act of 1978 |
Qualifying Facility(ies) | Certain small power production facilities are eligible to be “Qualifying Facilities” under PURPA, provided that they meet certain power and thermal energy production requirements and efficiency standards. Qualifying Facility status provides an exemption from PUHCA 2005 and grants certain other benefits to the Qualifying Facility |
RAM | Renewable Auction Mechanism |
REC | Renewable Energy Credit |
REG | Recovered Energy Generation |
RGGI | Regional Greenhouse Gas Initiative |
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RPS | Renewable Portfolio Standards |
RTO | Regional Transmission Organization |
SaaS | Software as a Service |
SCADA | Supervisory Control and Data Acquisition |
SCPPA | Southern California Public Power Authority |
SEC | U.S. Securities and Exchange Commission |
Securities Act | U.S. Securities Act of 1933, as amended |
Senior Unsecured Bonds | 7% Senior Unsecured Bonds Due 2017 issued by the Company |
SO#4 | Standard Offer Contract No. 4 |
SOL | Sarulla Operations Ltd. |
Solar PV | Solar photovoltaic |
SOX Act | Sarbanes-Oxley Act of 2002 |
Southern California Edison | Southern California Edison Company |
SPE(s) | Special purpose entity(ies) |
SRAC | Short Run Avoided Costs |
Southern California Edison | Southern California Edison Company |
SPE(s) | Special purpose entity(ies) |
SRAC | Short Run Avoided Costs |
Union Bank | Union Bank, N.A. |
U.S. | United States of America |
U.S. Treasury | U.S. Department of the Treasury |
VEI | Viridity Energy, Inc. |
Viridity | Viridity Energy Solutions Inc., our wholly owned subsidiary |
WHOH | Waste Heat Oil Heaters |
Cautionary Note Regarding Forward-Looking Statements
This annual report includes “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future, including such matters as our projections of annual revenues, expenses and debt service coverage with respect to our debt securities, future capital expenditures, business strategy, competitive strengths, goals, development or operation of generation assets, market and industry developments and the growth of our business and operations, are forward-looking statements. When used in this annual report, the words “may”, “will”, “could”, “should”, “expects”, “plans”, “anticipates”, “believes”, “estimates”, “predicts”, “projects”, “potential”, or “contemplate” or the negative of these terms or other comparable terminology are intended to identify forward-looking statements, although not all forward-looking statements contain such words or expressions. The forward-looking statements in this annual report are primarily located in the material set forth under the headings Item 1 — “Business” contained in Part I of this annual report, Item 1A — “Risk Factors” contained in Part I of this annual report, Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in Part II of this annual report, and “Notes to Financial Statements” contained in Item 8 — “Financial Statements and Supplementary Data” contained in Part II of this annual report, but are found in other locations as well. These forward-looking statements generally relate to our plans, objectives and expectations for future operations and are based upon management’s current estimates and projections of future results or trends. Although we believe that our plans and objectives reflected in or suggested by these forward-looking statements are reasonable, we may not achieve these plans or objectives. You should read this annual report completely and with the understanding that actual future results and developments may be materially different from what we expect due to a number of risks and uncertainties, many of which are beyond our control. Other than as required by law, we will not update forward-looking statements even though our situation may change in the future.
Specific factors that might cause actual results to differ from our expectations include, but are not limited to:
● | significant considerations, risks and uncertainties discussed in this annual report; |
● | geothermal resource risk (such as the heat content, useful life and geological formation of the reservoir); |
● | operating risks, including equipment failures and the amounts and timing of revenues and expenses; |
● | financial market conditions and the results of financing efforts; |
● | the impact of fluctuations in oil and natural gas prices and competition with other renewable sources on the energy price component under certain of our PPAs; |
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● | risk and uncertainties associated with our future development of storage projects which may operate as "merchant" facilities without long-term sales agreements, including the variability of revenues and profitabilty of such projects; |
● | environmental constraints on operations and environmental liabilities arising out of past or present operations, including the risk that we may not have, and in the future may be unable to procure, any necessary permits or other environmental authorizations; |
● | construction or other project delays or cancellations; |
● | political, legal, regulatory, governmental, administrative and economic conditions and developments in the |
● | the enforceability of long-term PPAs for our power plants; |
● | contract counterparty risk; |
● | weather and other natural phenomena including earthquakes, volcanic eruption, drought and other natural disasters; |
● | changes in environmental and other laws and regulations to which our company is subject, as well as changes in the application of existing laws and regulations; |
● | current and future litigation; |
● | our ability to successfully identify, integrate and complete acquisitions; |
● | competition from other geothermal energy projects and new geothermal energy projects developed in the future, and from alternative electricity producing technologies; |
● | market or business conditions and fluctuations in demand for energy or capacity in the markets in which we operate; |
● | there can be no assurance regarding when, if and to what extent opportunities under our commercial cooperation agreement with ORIX Corporation will in fact materialize; |
● | the direct or indirect impact on our company’s business of various forms of hostilities including the threat or occurrence of war, terrorist incidents or cyber-attacks or responses to such threatened or actual incidents or attacks, including the effect on the availability of and premiums on insurance; |
● | our new strategic plan to expand our geographic markets, customer base and product and service offerings may not be implemented as currently planned or may not achieve our goals as and when implemented; |
● | development and construction of Solar PV and energy storage projects, |
● | the effect of and changes in current and future land use and zoning regulations, residential, commercial and industrial development and urbanization in the areas in which we operate; and |
● | other uncertainties which are difficult to predict or beyond our control and the risk that we may incorrectly analyze these risks and forces or that the strategies we develop to address them may be unsuccessful. |
Certain Definitions
Unless the context otherwise requires, all references in this annual report to “Ormat”, “the Company”, “we”, “us”, “our company”, “Ormat Technologies”, or “our” refer to Ormat Technologies, Inc. and its consolidated subsidiaries. A glossary of certain terms and abbreviations used in this annual report appears at the beginning of this report.
Overview
We are a leading vertically integrated company that is currently primarily engaged in the geothermal and recovered energy power business. With the objective of becoming a leading global provider of renewable energy, we focus on several key initiatives, under our new strategic plan, as described below.
We design, develop, build, sell, own, and operate clean, environmentally friendly geothermal and recovered energy-based power plants, usually using equipment that we design and manufacture.
Our geothermal power plants include both power plants that we have built and power plants that we have acquired, while we have built all of our recovered energy-based plants. We recently expanded our operations to include the provision of services in the energy storage, demand response and energy management markets. We currently conduct our business activities in two business segments:
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We intend to expandIn March 2017, we expanded our operation to includeElectricity segment operations by entering the energy storage, demand response and energy management and storage. We recently signed an agreement to acquiremarkets following the acquisition of substantially all of the business and assets of Viridity Energy, Inc. (VEI), a privately held Philadelphia-based company with nearly a decade of expertise and leadership in demand response, energy management and storage.company. The acquired business and assets will beare owned and operated by our newly established wholly owned subsidiary Viridity Energy Solutions Inc. (Viridity). The acquisition, which is expected to close in early 2017, will mark Ormat’s entry into the growing energy storage and demand response markets. We intend to use our Viridity business to accelerate long-term growth, expand our market presence in a growing market, and further develop Viridity’sour energy storage, demand response and energy management services, including the VPower™ software platform and energy storage services.platform. We plan to continue to provideproviding services and products to existing Viridity customers, of the acquired business, while expanding our service offerings to include development and EPC into new geographiesregions and targeting a broader potential customer base.
The map below shows our worldwide portfolio of operating geothermal and recovered energy power plants as of February 27, 2017.March 1, 2018.
The charts below show the relative contributions of the Electricity segment and the Product segment to our consolidated revenues and the geographical breakdown of our segment revenues for ourthe fiscal year ended December 31, 2016.2017. Additional information concerning our segment operations, including year-to-yearyear-over-year comparisons of revenues, the geographical breakdown of revenues, cost of revenues, results of operations, and trends and uncertainties is provided below in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8 — “Financial Statements and Supplementary Data”.
The following chart sets forth a breakdown of our revenues for each of the years ended December 31, 20162017 and 2015:2016:
Segment Contribution to Revenues
The following chart sets forth the geographical breakdown of revenues attributable to our Electricity and Product segments for each of the years ended December 31, 20162017 and 2015:2016:
Geographical
Note: Electricity segment revenues for 2017 in the "Segment Contribution to Revenue" and "Geographic Breakdown of the Electricity Segment RevenuesRevenue" charts above include our energy storage and demand response activity.
Geographical Breakdown of the Product Segment Revenues
Most of the power plants that we currently own or operate produce electricity from geothermal energy sources. Geothermal energy is a clean, renewable and generally sustainable form of energy derived from the natural heat of the earth. Unlike electricity produced by burning fossil fuels, electricity produced from geothermal energy sources is produced without emissions of certain pollutants such as nitrogen oxide, and with far lower emissions of other pollutants such as carbon dioxide. As a result, electricity produced from geothermal energy sources contributes significantly less to global warming and local and regional incidences of acid rain than energy produced by burning fossil fuels. In addition, compared to power plants that utilize other renewable energy sources, such as wind or solar, geothermal power plants are generally available all the time and can provide base loadbase-load electricity services. In addition, theyservices. They can also be custom built to provide a range of services such as baseload, voltage regulation, reserves and flexible capacity. Geothermal energy is also an attractive alternative to other sources of energy as part of a national diversification strategy to avoid dependence on any one energy source or politically sensitive supply sources.
In addition to our geothermal energy business, we manufacture products that produce electricity from recovered energy or so-called “waste heat”. We also construct, own, and operate recovered energy-based power plants. Recovered energy comes from residual heat that is generated as a by-product of gas turbine-driven compressor stations, solar thermal units and a variety of industrial processes, such as cement manufacturing. Such residual heat, which would otherwise be wasted, may be captured in the recovery process and used by recovered energy power plants to generate electricity without burning additional fuel and without additional emissions.
Since 2015, we have begun to implementimplemented a number of elements of our new multi-year strategic plan.plan which was reviewed by our Board of Directors (the “Board”) in 2017. We expect the plan to evolve over time in response to market conditions and other factors. At this time, however, we expect that our primary focus will be as follows:
● | Expand our geothermal geographical reach. While we continue to evaluate opportunities worldwide, we currently see, |
● | Expand into new technologies. We ultimately hope to be able to leverage our technological capabilities over a variety of renewable energy platforms, including solar power generation and energy storage. Initially, however, we expect that our primary focus will be on expanding our core geothermal competencies |
● | Expand our customer base. We are evaluating a number of strategies for expanding our customer base to C&I customers. In the near term, however, we expect that a majority of our revenues will continue to be generated as they currently are, with our traditional electrical utility customer base for the Electricity segment and our on-going business development efforts for new customers for our Product segment. |
While we believe that long-term growth can be realized through our transformational efforts over time, there is no assurance if and when we will meet our objective to become a leading global provider of renewable energy or that such efforts will result in long-term growth. To be clear, weWe see these new initiatives as incremental measures to enhance shareholder value. While we implement the plan, we expect to continue, and expand, through organic growth, acquisitions, and other measures, our current business lines both in the Electricity and Product segments as well as other business lines as described above.
Company Contact and Sources of Information
We file annual, quarterly and periodic reports, proxy statements and other information with the SEC. You may obtain and copy any document we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington D.C. 20549. You may obtain information on the operation of the SEC’s Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and other information statements, and other information regarding issuers that file electronically with the SEC. Our SEC filings are accessible via the internet at that website.
Our reports on Form 10-K, 10-Q and 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available through our website at www.ormat.com for downloading, free of charge, as soon as reasonably practicable after these reports are filed with the SEC. Our Code of Business Conduct and Ethics, Code of Ethics Applicable to Senior Executives, Audit Committee Charter, Corporate Governance Guidelines, Nominating and Corporate Governance Committee Charter, Compensation Committee Charter, and Insider Trading Policy, as amended, are also available at our website address mentioned above. If we make any amendments to our Code of Business Conduct and Ethics or Code of Ethics Applicable to Senior Executives or grant any waiver, including any implicit waiver, from a provision of either code applicable to our Chief Executive Officer, Chief Financial Officer or principal accounting officer requiring disclosure under applicable SEC rules, we intend to disclose the nature of such amendment or waiver on our website. The content of our website, however, is not part of this annual report.
You may request a copy of our SEC filings, as well as the foregoing corporate documents, at no cost to you, by writing to the Company address appearing in this annual report or by calling us at (775) 356-9029.
Our Power Generation Business (Electricity Segment)
Power Plants in Operation
The table below summarizes certain key non-financial information relating to our power plants and complexes as of February 27, 2017.March 1, 2018. The generating capacity of certain of our power plants and complexes listed below has been updated from our 20152016 disclosure to reflect changes in the resource temperature and other factors that impact resource capabilities:
Type | Region | Plant | Ownership(1) | Generating capacity (MW) (2) | Region 2016 Capacity Factor |
Geothermal | California | Ormesa Complex | 100% | 40(3) | |
Heber Complex | 100% | 92 | |||
Mammoth Complex | 100% | 29 | |||
North Brawley | 100% | 18 | |||
78% | |||||
West Nevada | Steamboat Complex | 100% | 73 | ||
Brady Complex | 100% | 18 | |||
87% | |||||
East Nevada | Tuscarora | 100% | 18 | ||
Jersey Valley | 100% | 10 | |||
McGinness Hills | 100% | 86 | |||
Don A. Campbell | 63.3% | 41 | |||
97% | |||||
Hawaii | Puna | 63.3% | 38 | ||
78% | |||||
International | Amatitlan | 100% | 20 | ||
Zunil | 97% | 23 | |||
Olkaria III Complex | 100% | 139(4) | |||
Bouillante | 60% | 15(5) | |||
96% | |||||
Total Geothermal | 660 | 89% | |||
REG | OREG 1 | 63.3% | 22 | ||
OREG 2 | 63.3% | 22 | |||
OREG 3 | 63.3% | 5.5 | |||
OREG 4 | 100% | 3.5(6) | |||
Total REG | 53 | 83% | |||
Total | 713 |
Type | Region | Plant | Ownership(1) | Generating capacity (MW) (2) | Region 2016 Capacity Factor |
Geothermal | California | Ormesa Complex | 100% | 40 | |
Heber Complex | 100% | 89 | |||
Mammoth Complex | 100% | 29 | |||
Brawley | 100% | 13 | |||
77% | |||||
West Nevada | Steamboat Complex | 100% | 70 | ||
Brady Complex | 100% | 18 | |||
87% | |||||
East Nevada | Tuscarora | 100% | 18 | ||
Jersey Valley | 100% | 10 | |||
McGinness Hills | 100% | 90 | |||
Don A. Campbell | 63.3% | 41 | |||
Tungsten Mountain | 100% | 26(3) | |||
94% | |||||
Hawaii | Puna | 63.3% | 38 | ||
97% | |||||
International | Amatitlan (Guatemala) | 100% | 20 | ||
Zunil (Guatemala) | 97% | 23 | |||
Olkaria III Complex (Kenya) | 100% | 139 | |||
Bouillante (Guadeloupe Island) | 60%(4) | 15 | |||
Platanares (Honduras) | 100% | 35(5) | |||
94% | |||||
Total Consolidated Geothermal | 714 | 88% | |||
Unconsolidated Geothermal | Indonesia | Sarulla (SIL & NIL 1) | 12.75% | 28 | |
REG | OREG 1 | 63.3% | 22 | ||
OREG 2 | 63.3% | 22 | |||
OREG 3 | 63.3% | 5.5 | |||
OREG 4 | 100% | 3.5(6) | |||
Total REG | 53 | 84% | |||
Total | 795 |
| We indirectly own and operate all of our power plants, although financial institutions hold equity interests in | |
Notwithstanding our approximately 60% equity interest in the Bouillante power plant and 63.25% direct equity interest in the Puna, the first phase of Don A. Campbell, OREG 1, OREG 2 and OREG 3 power plants as well as the indirect interest in the second phase of the Don A. Campbell power plant owned by our subsidiary, ORPD LLC (“ORPD”), we list 100% of the generating capacity of the Bouillante power plant and the power plants in the ORPD portfolio in the table above because we control their operation. We list our 12.75% share of the generating capacity of the Sarulla power plant as we own a 12.75% minority interest. The revenues from the Sarulla project are not consolidated and are presented under “Equity in earnings (losses) of investees, net” in our financial statements.
| References to generating capacity generally refer to the gross generating capacity less auxiliary power in the case of all of our existing power plants, except the Zunil power plant. We determine the generating capacity figures in these power plants by taking into account the resource and power plant capabilities. In the case of the Zunil power plant, revenues are calculated based on a 24 MW capacity unrelated to the actual performance of the reservoir. This column represents our net ownership | |
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In any given year, the actual power generation of a particular power plant may differ from that power plant’s generating capacity due to variations in ambient temperature, the availability of the resource, and operational issues affecting performance during that year.
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| The 35 MW Platanares power plant in Honduras commenced commercial operation on September 26, 2017. |
6. | The OREG 4 power plant is not operating at full capacity because of low run time of the compressor station that serves as the power plant’s heat source. This results in lower power generation. |
All of the revenues that we derive from the sale of electricity are pursuant to long-term PPAs. Approximately 41.3%45.8% of our total revenues in the year ended December 31, 20162017 were derived from the sale of electricity by our domestic power plants to power purchasers that currently have investment grade credit ratings. The purchasers of electricity from our foreign power plants are either state-owned or private entities.
New Power Plants
We are currently in various stages of construction of new power plants and expansion of existing power plants. Our construction and expansion plan includes 110include 72 MW in generating capacity from geothermal power plants in the U.S., Honduras, Kenya and Indonesia that are fully released for construction. In addition, we have several projects in the U.S., Guadeloupe, IslandKenya and KenyaHonduras that are either under initial stages of construction or under different stages of development with an aggregate capacity of between 135115 MW and 140120 MW.
We have substantial land positions across 3432 prospects in the U.S., Guatemala, Guadeloupe, Kenya, New Zealand, Indonesia, Honduras and Ethiopia that we expect will support future geothermal development, on which we have started or plan to start exploration activity. These land positions are comprised of various leases, exploration concessions for geothermal resources and an option to enter into geothermal leases.
In addition, we are currently developing three storage systems, one behind-the-meter system and two in-front-of-the-meter (IFM)systems in New Jersey.
New activity
We recently signed an agreementOn to acquire substantially all of the business and assets of VEI, as mentioned above and further discussed under “Recent Developments”. We expect to completeMarch 15, 2017, we completed the acquisition early in fiscal year 2017 and for VEI'sof our Viridity business and assets to be owned by our newly established, wholly-owned subsidiary Viridity. Using proprietary software and solutions, Viridity will continue VEI’s business, serving primarily retail energy providers and large C&I customers. Viridity’s offerings will enable its clients to optimize and monetize their energy management, demand response and storage facilities potential by interacting on their behalf with regional transmission organizations and independent system operators.as described above.
With its VPowerOurTM software platform, Viridity will managebusiness currently manages curtailable customer loads of over 850875 MW across 3,000 sites under contracts with leading U.S. retail energy providers and directly with large C&I customers, including management of a portfolio of non-utility storage assets located in the northeastern U.S. with over 80,000 operational market hours. Viridity willWe serve itsour distributed customers through a network operations center (NOC), which is operated 24/7 based using Viridity’sour VPowerMarketsTM software platform and a SCADA platform. VPowerTM services will beare provided to customers using a SaaS model whereunder which we will receive license fees and/or a portion of the revenue and savings that are achieved for our Viridity customers.
We expect that the customer.eco system we created, combining our Viridity capabilities and our overall capabilities, including among others, our global presence, experience in technology and system integration, EPC of power generation projects, flexible business models, and our reputation and experience in the geothermal and recovered energy sectors, will enable us to expand in the growing energy storage sector.
In connection with this transaction, the Company will assumeacquisition of our Viridity business, we assumed certain contractual duties and obligations that are regulated by the FERCFederal Energy Regulatory Commission (FERC) and three RTOs.certain independent system operators (ISOs) and regional transmission organizations (RTOs). Specifically, Veridity will need to obtainour Viridity business obtained and maintain (1)maintains authorization from FERC to make wholesale sales of power, capacity, and ancillary services at market-based rates, and (2)we have confirmed membership status with eligibility to serve designated contractual functions inwithin each of the RTOs offollowing ISOs and RTOs: PJM the NYISO,Interconnection LLC (PJM), New York Independent System Operator, Inc. (NYISO), and the ERCOT. We have submittedElectric Reliability Council of Texas (ERCOT). Additionally, during the required applications to FERC and the RTOs and have alreadyfourth quarter of 2017, we received formal notice of membership in PJM.Midcontinent Independent System Operator (MISO) and ISO New England Inc. and have filed for membership in Independent Electricity System Operator (IESO – Ontario Canada). In the future, we may need to obtain and maintain similar membership and eligibility status with other RTOs where the newISO and RTO markets in which our Viridity business will operate.
Our Product Business (Product Segment)
We design, manufacture and sell products for electricity generation and provide the related services described below. We primarily manufacture products to fill customer orders, but in some situations, we may manufacture products as inventory for future internal and external projects.
Power Units for Geothermal Power Plants. We design, manufacture and sell power units for geothermal electricity generation, which we refer to as OECs. In geothermal power plants using OECs, geothermal fluid (either hot water (also called brine) or steam or both) is extracted from the underground reservoir and flows from the wellhead to a vaporizer that also heats a secondary working fluid, which is vaporized and used to drive the turbine. The secondary fluid is then condensed in a condenser, which may be cooled directly by air or by water from a cooling tower and sent back to the vaporizer. The cooled geothermal fluid is then reinjected back into the reservoir. Our customers include contractors and geothermal power plant developers, owners and operators.
Power Units for Recovered Energy-Based Power Generation. We design, manufacture and sell power units used to generate electricity from recovered energy, or so-called “waste heat”. This heat is generated as a residual by-product of gas turbine-driven compressor stations, solar thermal units and a variety of industrial processes, such as cement manufacturing, and is not otherwise used for any purpose. Our existing and target customers include interstate natural gas pipeline owners and operators, gas processing plant owners and operators, cement plant owners and operators, and other companies engaged in other energy-intensive industrial processes.
EPC of Power Plants. We engineer, procure, and construct,serve as an EPC contractor for geothermal and recovered energy power plants on a turnkey basis, using power units we design and manufacture. Our customers are geothermal power plant owners as well as our target customers for the sale of our recovered energy-based power units as described above. Unlike many other companies that provide EPC services, we believe we have an advantage in that we are using our own manufactured equipment that we manufacture and thus have better quality and better control over the timing and delivery of required equipment and its related costs. As part of our strategy and collaboration agreement with Toshiba, we might have EPC contracts that are based on Toshiba power units. We also expect to develop additional knowledge in integrating Toshiba power units combined with our OECs in order to maximize the benefits to our customers.
Remote Power Units and Other Generators. We design, manufacture and sell fossil fuel powered turbo-generators with capacities ranging from 200 watts to 5,000 watts, which operate unattended in extreme hot or cold climate conditions. Our customers include contractors who install gas pipelines in remote areas and off-shore platforms operators and contractors. In addition, we design, manufacture, and sell generators, including heavy duty direct-current generators, for various other uses.We are in the process of slowing down these activities.
History
We wereOrmat Technologies, Inc. was formed as a Delaware corporation in 1994 by our former parent company Ormat Industries. Ormat Industries was one of the first companies to focus on the development of equipment for the production of clean, renewable and generally sustainable forms of energy. On February 12, 2015, we successfully completed the acquisition of Ormat Industries in an all-stock merger, eliminating its majority ownership and control of us.Ormat Technologies.
Industry Background
Geothermal Energy
Most of our power plants in operation produce electricity from geothermal energy. There are several different sources or methods of obtaining geothermal energy, which are described below.
Hydrothermal geothermal-electricity generation — Hydrothermal geothermal energy is derived from naturally occurring hydrothermal reservoirs that are formed when water comes sufficiently close to hot rock to heat the water to temperatures of 300 degrees Fahrenheit or more. The heated water then ascends toward the surface of the earth where, if geological conditions are suitable for its commercial extraction, it can be extracted by drilling geothermal wells. Geothermal production wells are normally located within several miles of the power plant, as it is not economically viable to transport geothermal fluids over longer distances due to heat and pressure loss. The geothermal reservoir is a renewable source of energy if: (i) natural ground water sources and reinjection of extracted geothermal fluids are adequate over the long-term to replenish the geothermal reservoir following the withdrawal of geothermal fluids and (ii) the well field is properly operated. Geothermal energy power plants typically have higher capital costs (primarily as a result of the costs attributable to well field development) but tend to have significantly lower variable operating costs (principally consisting of maintenance expenditures) than fossil fuel-fired power plants that require ongoing fuel expenses.
EGS — An EGS is a subsurface system that may be artificially created to extract heat from hot rock where the permeability and aquifers required for a hydrothermal system are insufficient or non-existent. A geothermal power plant that uses EGS techniques recovers the thermal energy from the subsurface rocks by creating or accessing a system of open fractures in the rock through which water can be injected, heated through contact with the hot rock, returned to the surface in production wells and transferred to a power unit.
Co-produced geothermal from oil and gas fields, geo-pressurizedresources — Another source of geothermal energy is hot water produced as a by-product of oil and gas extraction. When oil and gas wells are deep, the extracted fluids are often at high temperatures and if the water volume associated with the extracted fluids is significant, the hot water can be used for power generation in equipment similar to a geothermal power plant.
Geothermal Power Plant Technologies
Geothermal power plants generally employ either binary systems or conventional flash design systems, as briefly described below. In our geothermal power plants, we also employ our proprietary technology of combined geothermal cycle systems.
Binary System
In a geothermal power plant using a binary system, geothermal fluid (either hot water (also called brine) or steam or both) is extracted from the underground reservoir and flows from the wellhead through a gathering system of insulated steel pipelines to a vaporizer that also heats a secondary working fluid. This is typically an organic fluid, such as pentane or butane, which is vaporized and is used to drive the turbine. The organic fluid is then condensed in a condenser, which may be cooled directly by air or by water from a cooling tower and sent back to the vaporizer through a pump. The cooled geothermal fluid is then reinjected back into the reservoir. Ormat’sThe operation of our air-cooled binary geothermal power plant is depicted in the diagram below.
Flash Design System
In a geothermal power plant using flash design, geothermal fluid is extracted from the underground reservoir and flows from the wellhead through a gathering system of insulated steel pipelines to flash tanks and/or separators. There, the steam is separated from the brine and is sent to a demister, where any remaining water droplets are removed. This produces a stream of dry saturated steam, which drives a steam turbine generator to produce electricity. In some cases, the brine at the outlet of the separator is flashed a second time (dual flash), providing additional steam at lower pressure used in the low pressure section of the steam turbine to produce additional electricity. Steam exhausted from the steam turbine is condensed in a surface or direct contact condenser cooled by cold water from a cooling tower. The non-condensable gases (such as carbon dioxide) are removed by means of a vacuum system in order to maintain the performance of the steam condenser. The resulting condensate is used to provide make-up water for the cooling tower. The hot brine remaining after separation of steam is injected (either directly or after passing through a binary plant to produce additional power from the residual heat remaining in the brine) back into the geothermal resource through a series of injection wells. The flash technology is depicted in the diagram below.
In some instances, the wells directly produce dry steam and the steam is fed directly to the steam turbine with the rest of the system similar to the flash power planttechnology described above.
Our Proprietary Technology
Our proprietary technology may be used either in power plants operating according to the Organic Rankine Cycle alone or in combination with various other commonly used thermodynamic technologies that convert heat to mechanical power, such as gas and steam turbines. It can be used with a variety of thermal energy sources, such as geothermal, recovered energy, biomass, solar energy and fossil fuels. Specifically, our technology involves original designs of turbines, pumps, and heat exchangers, as well as formulation of organic motive fluids (all of which are non-ozone-depleting substances). Using advanced computational fluid dynamics techniques and other computer aided design software as well as our test facilities, we continuously seek to improve power plant components, reduce operations and maintenance costs, and increase the range of our equipment and applications. We are always examining ways to increase the output of our plants by utilizing evaporative cooling, cold reinjection, configuration optimization, and topping turbines. In the geothermal as well as the recovered energy (waste heat) areas, we are examining two-level and three-level energy systems and other thermodynamic cycle alternations along with new motive fluids.
We also developed, patented and constructed GCCU power plants in which the steam first produces power in a backpressure steam turbine and is subsequently condensed in a vaporizer of a binary plant, which produces additional power. OrmatOur Geothermal Combined Cycle technology is depicted in the diagram below.
In the conversion of geothermal energy into electricity, our technology has a number of advantages over conventional geothermal steam turbine plants. A conventional geothermal steam turbine plant consumes significant quantities of water, causing depletion of the aquifer and requiring cooling water treatment with chemicals and thus a need for the disposal of such chemicals. A conventional geothermal steam turbine plant also creates a significant visual impact in the form of an emitted plume from the cooling towers, especially during cold weather. By contrast, our binary and combined cycle geothermal power plants have a low profile with minimumminimal visual impact and do not emit a plume when they use air-cooled condensers. Our binary and combined cycle geothermal power plants reinject all of the geothermal fluids utilized in the respective processes into the geothermal reservoir. Consequently, such processes generally have no emissions.
Other advantages of our technology include simplicity of operation easy and maintenance and higher yearly availability. For instance, the OEC employs a low speed and high efficiency organic vapor turbine directly coupled to the generator, eliminating the need for reduction gear. In addition, with our binary design, there is no contact between the turbine blade and geothermal fluids, which can often be very corrosive and erosive. Instead, the geothermal fluids pass through a heat exchanger, which is less susceptible to erosion and can adapt much better to corrosive fluids. In addition, with the organic vapor condensed above atmospheric pressure, no vacuum system is required.
We use the same elements of our technology in our recovered energy products. The heat source may be exhaust gases from a Brayton cycle gas turbine, low-pressure steam, or medium temperature liquid found in the process industries such as oil refining and cement manufacturing. In most cases, we attach an additional heat exchanger in which we circulate thermal oil or water to transfer the heat into the OEC’sOEC’s own vaporizer in order to provide greater operational flexibility and control. Once this stage of each recovery is completed, the rest of the operation is identical to that of the OECs used in our geothermal power plants and enjoys the same advantages of using the Organic Rankine Cycle. In addition, our technology allows for better load following than conventional steam turbines, requires no water treatment (since it is air cooled and organic fluid motivated), and does not require the continuous presence of a licensed steam boiler operator on site.
OrmatOur ’s REG technology is depicted in the diagram below.
Patents
We have 7377 U.S. patents that are in force (and have approximately 169 U.S. patents pending). These patents and patent applications cover our products (mainly power units based on the Organic Rankine Cycle) and systems (mainly geothermal power plants and industrial waste heat recovery plants for electricity production). The products-related patents cover components that include turbines, heat exchangers, seals and controls as well as control of operation of geothermal production well pumps. The system-related patents cover not only particular components but also the overall energy conversion system from the “fuel supply” (e.g., geothermal fluid, waste heat, biomass or solar) to electricity production.
The system-related patentsalso cover subjects such as waste heat recovery related to gas pipeline compressors and industrial waste heat, solar power systems, disposal of non-condensable gases present in geothermal fluids, power plants for very high pressure geothermal resources, two-phase fluids, low temperature geothermal brine as well as processes related to EGS. A number of our patents cover combined cycle geothermal power plants, in which the steam first produces power in a backpressure steam turbine and is subsequently condensed in a vaporizer of a binary plant, which produces additional power. The remaining terms of our patents range from one year to 1816 years. The loss of any single patent would not have a material effect on our business or results of operations.
Research and Development
We are conducting research and development activities intended to improve plant performance, reduce costs, and increase the breadth of our product offerings. The primary focus of our research and development efforts is targeting power plant conceptual thermodynamic cycle and major equipment including continued performance, cost and land usage improvements to our condensing equipment, and development of new higher efficiency and higher power output turbines.
Our Viridity business continues to develop new optimization algorithms to optimize the life of a battery energy storage system (BESS), to optimize our and our customers’ economic return and to forecast the trends surrounding our customers’ electricity consumption and the electric grid including times of peak demands and the usage of ancillary services.
We have also focused our development efforts on the engineering and design of improved energy storage systems. These development efforts include, among others, further development of the control hardware and software for energy storage systems to follow electric grid and market signals and to optimize their delivery of energy into the markets using our VPower™ software and SCADA platform to accelerate system optimization through cloud base algorithms.
We have developed, and continue to develop, system integration capabilities that match the appropriate system and system sizing with the appropriate battery chemistry, electrical and physical components to accommodate our needs or needs of the customers that will own such energy storage systems in light of the markets in which they will operate. We are searching for alternative chemistries, products and combinations of hybrid solutions to best address our energy storage product customers’ needs.
Additionally, we are continuing to evaluate investment opportunities in new companies with technology and/or product offerings for renewable energy and energy storage solutions.
Market Opportunity
Geothermal Market Opportunities
United States
Interest in geothermal energy in the U.S. remains strong for numerous reasons, including legislative support, of RPS goals, coal and nuclear base load energy retirementbase-load retirements, and increasing awareness of the positive value of geothermal characteristics as compared to intermittent renewable technology.technologies.
Today, electricity generation from geothermal resources is concentrated mainly in California, Nevada, Hawaii, Idaho, Oregon, and Utah, and we believe there are opportunities for development in other states such as Arizona, New Mexico Washington and Oregon due to the potential of their geothermal resources.
In a report issued in March 2016, the GEA indicated that the U.S. geothermal industry had about 3,700 MW of installed nameplate capacity and over 80 active projects with a cumulative capacity of over 1,250 MW of geothermal projects under various phases of consideration or development in 10 U.S. states.
Geothermal energy provides numerous benefits to the U.S. grid and economy, according to another GEA report issued in January 2017. Geothermal development and operation brings economic benefits in the form of taxes and long term high-paying jobs, and it currently has one of the lowest LCOE of all power sources in the U.S. Additionally, improvements in geothermal production make it possible to provide ancillary and on-demand services. This helps load serving entities avoid additional costs from purchasing and then balancing intermittent resources with storage or new transmission.
In recent years, according to the GEA, the U.S. geothermal market experienced modest growth and a decline in the development inventory of geothermal projects. This decline can be attributed to projects reaching completion, industry consolidation, and developers discontinuing projects they elected to put on hold for the time being. Management’s view is that this decline is also caused by an unbalanced mechanisms for valuing baseload power and integration costs in California and Nevada where a significant amount potential of U.S. geothermal resources are located. Most integration costs are not accounted for in bids for renewable resources. This creates an advantage for the intermittent resources as they receive a free pass for costs they create as compare to the positive attributes and ancillary benefits of baseload resources. Not all buyers accurately account for the negative impact of intermittent renewables in areas such as curtailment due to over-generation, strains on the transmission grid, the need for backup capacity, the diminishing value of energy during solar PV hours, the inefficient use of transmission capacity etc. Buyers also typically do not properly value the flexibility benefits of geothermal resource.
The successful implementation of the various geothermal projects identified by the GEA depends on the respective project sponsor’s ability to fully identify the resource, conduct exploration, and carry out development and construction. Accordingly, the GEA estimates may not be realized, and differences between the actual number of projects completed and those initially estimated to be completed may be material. We refer to the GEA assessment as a possible reference point, but we do not necessarily concur with its estimate.
State level legislation
One of the factors supporting growth in the renewable energy industry is global concern about climate change. In response to increasing demand for “green” energy, many states have adopted legislation requiring, and providing incentives for, electric utilities to sell electricity generated from renewable energy sources. In the U.S., 37 states plus the District of Colombia and four territories have enacted an RPS, renewable portfolio goals, or similar laws requiring or encouraging utilities in such states to generate or buy a certain percentage of their electricity from renewable energy or recovered heat sources.
According to the Database of State Incentives for Renewables and Efficiency (DSIRE), 30 states and two territories (including California, Nevada, and Hawaii, where we have been the most active in our geothermal energy development and in which all of our operating U.S. geothermal power plants are located), two territories, and the District of Columbia define geothermal resources as “renewable”. In addition, according to the EPA, 25 states have enacted RPS, Clean Energy Standards, Energy Efficiency Resource Standards or Alternative Portfolio Standards program guidelines that include some form of combined heat and power and/or waste heat recovery.
We see the impact of RPS legislation as the most significant driver for us to expand existing power plants and to build new projects.
California
The California RPS was established in 2002 under Senate Bill (SB) 1078, accelerated in 2006 under SB 107 and further expanded in 2011 under SB x1-2. The’s RPS program now requires Load Serving Entities (LSEs), including investor-owned utilities (IOUs), electric service providers, community choice aggregators, and publicly owned utilities to increase their share of procurement from eligible renewable energy resources as a percentage of their total procurement. The RPS requirements for utilitiesrequires LSEs to procure of 33 percent of their energy from renewable resources by 2020, was revised in October 2015, when Governor Jerry Brown signed into law SB 350 requiring thatramping up to 50 percent of total retail electricity sales be from renewable resources byin 2030, with interim targets of 40 percent by 2024 and 45 percent by 2027.
According to the CPUC Renewable Portfolio Standard Quarterly Report for the fourth quarter of 2016, California’s three largest IOUs collectively generated 27.6% of their 2015 retail electricity sales from renewable resources. These utilities have interim targets each year, with a requirement to attain The expanded RPS of 25% by 2016. Publicly-owned utilities in California are also required to procure 50% of retail electricity sales from eligible renewable energy resources by 2030, opening up an additional market of potential off-takers for us. This expanded target couldshould benefit geothermal energy, which has the advantage of generating flexible base load power, and helping California diversify its mix of renewable resources.
In 2006, California passed a state climate change law, Assembly Bill (AB) 32, to reduce GHG emissions to 1990 levels by the end of 2020, and in December 2010, the CARB approved cap-and-trade regulations to reduce California’s GHG emissions below the levels set by AB 32. The regulations set a limit on emissions from sources responsible for emitting 80% of California’s GHGs. On November 2016, the CARB released the results of its ninth joint auction for California and Québec allowances reporting that the vintage 2016 auction clearing price was $12.73 per allowance and the future vintage auction clearing price was $12.73 per allowance. All of the available 2016 and vintage allowances offered were sold.
In 2014, AB 2363 became effective, requiring the CPUC to adopt, by December 31, 2015, a methodology for determining the costs of integrating eligible renewable energy resources. The process has experienced some delays, and currently, the CPUC is incorporating the development of this methodology into its Integrated Resource Planning process. We expect thatWhile the CPUC will issue newhas issued draft guidelines for integrated resource planning in this regard in 2017.late 2017, the renewable integration issues assessment remain unresolved. The CPUC has implemented a capacity assessment mechanism that tends to favor dispatchable resources, including geothermal, giving them a higher overall capacity value than variable resources such as wind and solar.
Nevada
In 2016, Nevada’s RPS was first adopted by the Nevada Legislature in 1997. Nevada’s RPS targets were revised and expanded and currently require NV Energy to supply at least 25% of the total electricity it sells from eligible renewable energy resources by 2025. For 2015, Nevada’s RPS required that at least 20% of electricity sold to Nevada retail customers be from renewable energy resources and credits, and at least 5%6% of that amount be from solar resources. According to NV Energy’s Annual RPS Compliance Report, in 2015,2016, both Nevada Power and Sierra Pacific Power exceeded both the 20152016 RPS standard requirements, achieving a total of 22.2% and the 2015 solar RPS requirement, achieving 21.2% and 31.0%,26.6% respectively. Sierra exceeded both the 2015 RPS standard and the 2015 solar RPS requirement, with 31.3% and 22.8% respectively.
In June 2013, the Nevada state legislature passed three bills that were signed into law and expected to support renewable energy development. SB No. 123 requires an electric utility to submit a plan for the retirement or elimination of not less than 800 MW of coal-fired electric generating capacity on or before December 31, 2019 and the construction or acquisition of, or contracting for, 350 MW of electric generating capacity from renewable energy facilities. SB No. 252 revises provisions relating to the renewable portfolio standard by removing energy efficiency, solar multipliers, and station usage from generating portfolio energy credits (PECs). Finally, AB No. 239 Revised Statutes 701A.340 defines geothermal energy as renewable energy for purposes of tax abatements and makes geothermal projects eligible to apply for partial sales and property tax abatements, with property tax abatements for 20 years and local sales and use tax abatements for three years.
Hawaii
Hawaii established a renewable portfolio goal in 2001. Since 2001, the RPS targets were revised and expanded. On June 2015, Hawaii became the only state with a legislative goal of 100% renewable energy by 2045 with the signing of HB 623. The new policy includes interim requirements of 15% by the end of 2015, 30% by the end of 2020, 40% by 2030, and 70% by 2040, ultimately reaching 100% renewable electricity by 2045.
In 2016, Hawaiian Electric Company and its subsidiaries exceeded the 2015 RPS requirement, achieving a consolidated RPS of 23.2%25.8% of retail electricity sales from eligible renewable energy resources.
Multi-State Climate Initiatives
Other state-wide and regional initiatives are also being developed to reduce GHG emissions and to develop trading systems for renewable energy credits. For example, nine Northeast and Mid-Atlantic States are part of the RGGI, a regional cap-and-trade system to limit carbon dioxide. The RGGI was the first, market-based carbon dioxide emissions reduction program in the U.S. The RGGI states implemented a new 2014 RGGI cap of 91 million short tons and plan to reduce carbon emissions from power plants at a rate of 2.5% per year between 2015 and 2020. States sell nearly all emission allowances through auctions and invest proceeds in energy efficiency, renewable energy and other consumer benefit programs. These programs are spurring innovation in the clean energy economy and creating green jobs in the RGGI states.
In addition to RGGI, other states have also established the Midwestern Regional Greenhouse Gas Reduction Accord and the Western Climate Initiative.
Although individual and regional programs will take some time to develop, their requirements, particularly the creation of any market-based trading mechanism to achieve compliance with emissions caps, should be advantageous to in-state and in-region (and, in some cases, such as RGGI and the State of California, inter-regional) energy generating sources that have low carbon emissions such as geothermal energy. The role or importance of such programs remains unclear following the 2016 U.S. presidential election.
In December 2015, the White House announced that 154 companies from across the American economy signed the American Business Act on Climate Pledge to demonstrate their support for action on climate change. By signing the American Business Act on Climate pledge, these companies are demonstrating an ongoing commitment to climate action. As part of this initiative, each company is announcing significant pledges to reduce their emissions, increase low-carbon investments, deploy more clean energy, and take other actions to build more sustainable businesses and tackle climate change.
Although it is currently difficult to quantify the direct economic benefit of these efforts to reduce GHG emissions, we believe they will prove advantageous to us.
Federal level legislation
On August 3, 2015, President Obama and the EPA announced the Clean Power Plan that sets standards for power plants and customized goals for states to cut carbon pollution. The goal of the proposed plan includes cutting carbon emissions from the power sector by 32% below 2005 levels nationwide by 2030. In February 2016, the Supreme Court of the U.S. granted a temporary stay halting implementation of the Clean Power Plan pending resolution of legal challenges to the proposed plan. The U.S. Court of Appeals for the District of Columbia Circuit heard oral arguments in the cases challenging the Clean Power Plan on September 27, 2016. The court has not
On March 28, 2017, President Donald Trump signed the Executive Order on Energy Independence (E.O. 13783), which in part calls for a review of the Clean Power Plan. On October 10, 2017, the EPA issued its decision, and it remains unclear exactly what actiona Notice of Proposed Rulemaking (NPRM), proposing to repeal the Trump Administration will take, although the Trump Administration has expressed its desire to eliminateClean Power Plan. After reviewing the Clean Power Plan, and general skepticism of climate change.the EPA has proposed to determine that the Obama-era regulation exceeds the agency’s statutory authority.
The federal government also encourages production of electricity from geothermal resources or solar energy through certain tax subsidies. For a new geothermal power plant in the U.S. that started construction by December 31, 2016,2017, we are permitted to claim aan investment tax credit basedfor 30 percent of the project cost in the year the project is put in service or production tax credits over time on the power produced from a geothermal power plant. Theseproduced. The production-based credits, which in 20162017 were 2.32.4 cents per kWh, are adjusted annually for inflation and may be claimed for ten10 years on the net electricity produced by the project andoutput sold to third parties after the project is first placed in service. In lieuAny project that started construction by December 2017 must ordinarily be put in service within four years after the end of the productionyear in which construction started to qualify for tax credits at these rates. For a new geothermal power plant in the U.S. that started construction after 2017, we are permitted to claim a tax credit against our U.S. federal income taxes equal to 30% of certain eligible costs when the project is placed in service, so long as the project was under construction by the end of 2016. If the project was not under construction in time, then we are permitted to claim a 10% investment tax credit. The owner of the power plant may not claim both thean investment tax credit andof 10 percent of the production-based tax credit. project cost.
New solar projects that are under construction by December 2019 will qualify for a 30%30 percent investment tax credit. The credit will fall to 26%26 percent for projects starting construction in 2020 and 22%22 percent for projects starting construction in 2021. ProjectsProjects that are under construction before these deadlines must be placed in service by December 31 2023 to qualify for the higher investment tax credit. Projectscredits at these rates. Solar projects placed in service after December 31, 2023 will only qualify for a 10%10 percent investment tax credit.credit, on par with the permanent credit provided to geothermal. Under current tax rules, any unused tax credit has a one-year carry back and a twenty-year carry forward.
WeThe tax credits are potentially exposed to claw back under a new base erosion and anti-abuse tax or "BEAT" that took effect on January 1, 2018. See the discussion under Item 1A — “Risk Factors”.
New U.S. federal tax legislation, commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”), enacted at the end of December 2017 reduced the corporate income tax rate from 35 percent to 21 percent starting in 2018. This is likely to reduce the amount of tax equity that can be raised to finance renewable energy projects but should increase after-tax earnings from operating projects after the initial period when the project is being depreciated.
The Tax Act also permitted to depreciate, or write off, most ofallows the cost of new or used equipment purchased from third parties to be "expensed" or deducted immediately. This change applies to equipment put in service after September 27, 2017. However, it does not apply to equipment that we contracted to acquire on or before September 27. This full expensing applies to equipment put in service through 2022. After that, the plant. In cases where we claim the one-time 30% (or 10%) tax credit, our tax basispercentage that can be expensed drops by 20 percent a year until it reaches zero in 2027.
There are other changes in the plantTax Act that we can recover through depreciationare potentially favorable to us, such as U.S. corporations will no longer be taxed on dividends from foreign corporations in which they own at least a 10 percent interest to the extent the dividends are paid out of future earnings earned outside the U.S., and income from cross-border sales of turbines and other "inventory" will be treated as earned in the country where the items were manufactured rather than earned partially or entirely in the country where the inventory is reduced by one-halfsold. There are also other potentially unfavorable provisions, such as a new annual tax on global intangible low--taxed income, or "GILTI." We have not yet made a full assessment of the tax credit. In cases where we claim the production tax credit, there is no reduction in the tax basis for depreciation. Projects that are placed in service in 2016 and 2017 are eligible for “bonus” depreciation and we will be permitted to write off 50%impact of the costTax Act on our future earnings or operations. See Item 7 — “Management’s Discussion and Analysis of that equipment in the year the power plant is placed in service. Projects placed in service in 2018 would qualifyFinancial Condition and Results of Operations” for a 40% bonus and Projects placed in service in 2019 would qualify for a 30% bonus. After applying any depreciation bonus that is available, we can write off the remainder of our tax basis in the plant, if any, 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.further discussion.
Collectively, these benefits (to the extent they are fully utilized) have a present value equivalent to approximately 30% to 40% of the capital cost of a new power plant.
Global
We believe the global markets continue to present growth and expansion opportunities in both established and emerging markets.
According to the GEA’s Geothermal Power: International Market Update, the global geothermal market was developing about 2.5 GW of planned capacity spread across 23 countries. Additionally, the GEA estimates that, based on current data, the global geothermal industry is expected to grow from 13.8 GW today to reach 23 GW by 2021.
The assessment conducted by the GEA is only an estimate that is based on projects and resource reporting by the geothermal industry. A developer’s ability to fully develop a geothermal resource is dependent upon its capabilities to identify the resource and conduct exploration, development and construction; therefore, this estimate may not be accurate. We refer to it only as a possible reference point, but we do not necessarily concur with this estimate.
Operations outside of the U.S. may be subject to and/or benefit from increasing efforts by governments and businesses around the world to fight climate change and move towards a low carbon, resilient and sustainable future. According to a 2017 report from the International Renewable Energy Agency entitled Rethinking Energy, to date, more than 170 countries have established renewable energy targets, and nearly 150 have enacted policies to catalyze investments in renewable energy technologies.
In December 2015, 197 countries signed an historic agreement at the COP21 UN Climate Change Conference held in Paris. For the first time, all countries committed to setting nationally determined climate targets and reporting on their progress. The agreement’sagreement’s aim is to keep global temperature rise this century well below 2 degrees Celsius and to drive efforts to limit the temperature increase even further to 1.5 degrees Celsius above pre-industrial levels. According to the United Nations Framework Convention on Climate Change (UNFCCC),the submission of national targets in five-year cycles signals to investors and technology innovators that the world will demand clean power plants, energy efficient factories and buildings, and low-carbon transportation in the decades to come.
The Paris Agreement entered into force on November 4, 2016, thirty days after the date on which at least 55 parties to the Convention accounting in total for at least an estimated 55% of the total global greenhouse gas emissions deposited their instruments of ratification, acceptance, approval oror accession with the Depositary. 127 Parties have ratified of 197 Parties to the Convention.
On June 1, 2017, President Donald J. Trump announced that the U.S. will withdraw from the Paris Climate Accord and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the U.S.
In support of the Paris agreement, the EIB has committed to provide $100 billion of new financing for climate action projects over the five years. The support of multilateral institutions such as EIB is expected to be an important factor in assisting countries in reaching their targets under the Paris Climate Change Agreement.
In November 2015, a group of 20 countries, including the US, UK, France, China and India, pledged to double their budget for renewable energy technology over the next five years as part of a separate initiative called Mission Innovation.
Also, in November 2015, the Breakthrough Energy Coalition was launched by a group of 28 private investors with the objective of bringing companies with the potential to deliver affordable, reliable and carbon free power from the research lab to the market.
We believe that these developments and governmental plans will create opportunities for us to acquire and develop geothermal power generation facilities internationally, as well as create additional opportunities for our Product segment.
Outside of the U.S., the majority of power generating capacity has historically been owned and controlled by governments. Since the early 1990s, however, many foreign governments have privatized their power generation industries through sales to third parties encouraging new capacity development and/or refurbishment of existing assets by independent power developers. These foreign governments have taken a variety of approaches to encourage the development of competitive power markets, including awarding long-term contracts for energy and capacity to independent power generators and creating competitive wholesale markets for selling and trading energy, capacity, and related products. Some foreign regions and countries have also adopted active government programs designed to encourage clean renewable energy power generation such as the following countries in which we operate and/or are conducting business development activities:
Europe
Turkey hasis the richest knownfastest growing geothermal resources in Europemarket worldwide with the theoretical potential for 31,000 MW31 GW of geothermal capacity and with a proven geothermal capacity of 4.5 GW, according to the Turkish Mineral Technical Exploration Agency.
Since 2004, we have established strong relationships in the Turkish market and provided our full range of solutions including our state-of-the-art binary systems to 28 geothermal power plants with a total capacity of nearly 515 MW, of which 6 power plants are currently under construction.
In Turkey, the National'National Renewable Energy Action Plan' proposes to increase the country's renewable energy generation capacity to 61 GW by 2023, including 1.5 GW of geothermal. Theelectricity generation from geothermal resources. This plan is supported by the European Bank for ReconstructionReconstruction and Development. The plan aims to increase Turkish energy security by diversifying its energy supply, makemaking greater use of domestic resources, protectprotecting the environment by relying on clean, renewable and low carbon technologies and fosterfostering energy market efficiency through private sector investment and integration.
The plan also seeks to attract private investments in research and development and in geothermal exploitation for electricity production and to provide financial support to innovation and technology research in the field of renewable energies.energy. Special emphasis and attention has been placed on using locally manufactured equipment in renewable energy based generating facilities, with a target set for 45%the amount of major and critical equipment that is manufactured locally to be used in such facilities by the end of 2019 to be manufactured locally.2019.
To achieve its objective of having 30% of its power generated from renewable sources by 2023, Turkey has changed theits renewable energy law first enacted in 2007. TheThe law sets the FITsfeed-in-tariff (FIT) for electricity generated from geothermal energyresources at $105 per MWh for ten years from the COD of the relevant project and provides a further incentive of $13 per MWh for local manufacturing of turbine related parts for five years from COD. This last updatethe COD of the relevant project. This law, as amended, is valideffective until 2020. Renewable energy producers will also benefit from an 85% discount on transmission costs for 10 years and various priority rights over land usage. In order to benefit from the incentives under the renewable energy law, a renewable energy generation facility must hold a renewable energy resource certificate (the RER Certificate), which is issued by Turkey’s Energy Market Regulatory Authority. TheAn RER Certificate will becertificate is valid for the term of the generation license of the relevant generation company. In addition, and to avoid rights and licenses manipulation, a pre-feasibility license must be issued and paid for upon the request to hold a concession. These pre-licenses must be turnedconverted into full licenses for developed fields within three years of issuance, or they become void and the license rights may be re-assigned without fee reimbursement.
To address the demand for local production, we established a local subsidiary in Turkey, which has obtained all certifications required to be obtained by a local manufacturer of parts and equipment in accordance with the Turkish legislation described above.
Latin America
Several Latin American countries have renewable energy programs. In November 2013, the national government of Guatemala, where our Zunil and Amatitlan power plants are located, approved a law creating incentives for power generation from renewable energy sources. These incentives include, among other things, providing economic and fiscal incentives such as exemptions from taxes on the importation of relevant equipment and various tax exemptions for companies implementing renewable energy projects. Additionally, the Energy Policy 2013-2027 identifies great untapped potential for renewable energy production in Guatemala, including 1,000 MW for geothermal. One of the main objectives of the Energy Policy is to secure a supply of electricity at competitive prices by diversifying the energy mix with an 80% renewable energy share target for 2027.
In Honduras, where we are buildingrecently completed the construction of the first geothermal power plant under a BOT agreement, theagreement. The national government of Honduras approved the Incentives Act (Decree No.70-2007) providing, which provide incentives in the form of tax exemptions for equipment, materials and services related to power generation development based on renewable resources. At the same time, ENEE, the national integrated utility, will buy energy from such projects and offer to pay rates that are above the marginal cost approved by the CNE. Honduras also set a target to reach at least 80% renewable energy production by 2034.
In Chile, the Chilean Renewable Energy Act of 2008 required 5% of electricity sold, to come from renewable sources, increasing gradually to 10% by 2024. On October 14, 2013, the President of Chile signed into law a bill which mandates that utilities source 20% of their electricity from “non-conventional” renewable energy, including solar PV and concentrating solar power, by 2025.
Mexico is the world’s fourth largest producer of geothermal energy. Recent studies suggest an over 9,000 MW9 GW geothermal potential, of which only approximately 12% is already developed. In December 2013, the Mexican Congress passed a constitutional reform in an attempt to increase the participation of private investors in the generation and commercialization of electric energy. This reform affects the electricity market by opening the generation and commercialization of electricity to private companies, transforming theMexico’s Federal Electricity Commission to a for-profit public company, and redefining the functions and attributions of the Ministry of Energy. The secondary legislation that establishes the attributions of the public entities, procurement regulations, and a normative framework for the productive Statestate-owned energy companies was finalized in 2014.
In July 2015, Mexico launched round zero and assigned the projects to be developed by Mexico's state-owned utility CFE, with the remainder to be put out to tender to the private sector. Thirteen geothermal areas and five concessions were given by the Mexican Secretariat of Energy to the CFE. The government expects to award private companies with concessions for 30 years and exploration permits for up to 150 km2 for three years in the case of exploration. Ormat isyears. We are in various discussions with local companies to identify attractive geothermal resources and projects.
Caribbean
Many island nations in general and specifically the Caribbean nations, depend almost entirely on petroleum to meet their electricity demands.needs. With an average electricity price of US$35approximately $35 per kWh in 2014, the lack of diversified power generation leaves Caribbean nations vulnerable to commodity market volatility, while the lack of new development leaves them reliant on what are believed to be outdated and often unreliable power plants. The larger issue hindering large-scale renewable energy deployments, however, is scale. Caribbean nations have quite significant renewable energy potential, yet most have small demand. The majority of the Caribbean grids are relatively old, with the average diesel generatorsgenerator more than 20 years old. Furthermore, the power supply is relatively inefficient with high system losses. Due to their sizes, each of the Caribbean countries is generally dominated by one local utility and simple market structures where electricity is regulated directly by local governments. Other than in Guadeloupe, where the geothermal power plant that we recently acquired has been operating since 1985, there are no other operating geothermal projects in the Caribbean region. Recently, some deep well drilling exploration was performed on a few islands, but the results of this exploration are still pending. Although few, we believe there are opportunities for us in the Caribbean islands of St. Kitts, Nevis, St. Lucia, Dominica, and Montserrat.
Oceania
In New Zealand, where we have been actively providing geothermal power plant solutions since 1988, the New Zealand government’s policies to fight climate change include an unconditional GHG emissions reduction target of between 10% and 20% below 1990 levels by 2020 and a target to increase renewable electricity generation totarget of 90% of New Zealand’s total electricity generation by 2025. We continue selling power plant equipment to our New Zealand customers and secured two projects in the last two years.
South East Asia
In Indonesia, where we participateOrmat holds a 12.75% equity interest in the Sarulla project that is expected to startin Indonesia. The first 110 MW phase commenced commercial operation of the first unit in March 2017, the second 110 MW phase commenced commercial operation in October 2017, and where two other units arethe third 110 MW phase is currently under construction, with plans to commence commercial operation in the second quarter of 2018.
The Indonesian government intends to increase the roleshare of renewable energy sources and aimsin the energy mix, aiming to have them meet a target of 23% of domestic energy demand by 2025. The government has also implemented new policies and regulations intended to accelerate the development of renewable energy and geothermal projects in particular. In June 2014, the MEMR issued a new geothermal tariff policy. The MEMR reverted to a location-based tariff regime while adding a time dimension. The tariffs range from $0.118 to $0.296 per kWh between 2015 and 2025, depending on location. The tariffs provide a ceiling price for the power purchase agreements between project developers and PLN, the national utility and off taker. The tariffs were set to include the effect of inflation on projects that are expected to commence commercial operation in the distant future.
In addition, the 2014 National Energy Policy calls for the increased use of geothermal energy to represent at least 5% of the national energy mix by 2025.
In order to further accelerate geothermal development in the country a new FIT regime is expected to become effective during early 2017. The FIT is planned to range from $0.12 to $0.24 per kWh depending on size and location. Additionally, in January 2016, the government of Indonesia announced it will offer 21 geothermal blocks to investors over the next two years. Ormat plans to participate in select appropriate bids.
In the IPP sector, certain regulations for geothermal projects have been implemented, providing incentives such as investment tax credits, accelerated depreciation, and pricing guidelines to allow for preferential power prices for generators.
OnThe Indonesian government announced its intention to reduce the country’s carbon dioxide emissions by 26% by 2020 at the 2009 United Nations Climate Change Conference in Copenhagen and during 2015 in Paris.
In January 2016, the President of Indonesia issued new presidential regulations (PR No. 4 2016) to accelerate the Indonesian 35 GW Power Generation Program. The regulations introduce a new government guarantee for the development of power projects, which would cover both projects developed by the state-owned utility company, PLN, and those projects developed by PLN in cooperation with IPPs or their subsidiaries. Additionally, a shorter period to obtain necessary permits for development was introduced as well as clarifications that geothermal projects can be developed in high-conservation forest areas (e.g. national parks).
The Government of IndonesiaIndonesian government is planning to revise negative investmentinvestment regulation. According to Presidential Decree No. 39/2014, the development of geothermal power plants with a capacity of less than 10 MW is closed to foreign ownership. Currently, foreign investors may own up to 95 percent95% of power plants with generating capacities greater than 10 MW. The revised regulations currently under government review, will allow foreign entitiesinvestors to wholly own up to 100% of geothermal power plants, with generating capacities greater than 10 MW and up to own 67% of smaller sized geothermal power plants with generating capacities of less than 10 MW.
In late 2016, the Indonesian government attempted to bring the national electricity provision with lower cost and minimized subsidies. In February 2017, the MEMR issued two regulations: No. 10/2017, which regulates the key terms of PPAs and No. 12/2017, which regulates the utilization of renewable energy for the provision of electricity. However, in August 2017, MEMR regulation No. 10/2017 was amended by the regulation MEMR No 49/2017, and regulation MEMR No. 12/2017 was replaced by regulation MEMR No. 50/2017.
Under MEMR No. 50/2017, the tariff policy for geothermal PPAs is mainly determined based on the location of the relevant power plant. For geothermal projects located in Java, Sumatera, Bali and certain other regions that have a local electricity generation cost (the “Local BPP”) below or equal to the national average electricity generation cost (the “National BPP”), the tariff will be based on rates negotiated by the developer and PLN.
For geothermal projects located in regions with a Local BPP that is higher than the National BPP, the ceiling tariff is set to the Local BPP.
In addition to project development, we are also pursuing various supply opportunities in Southeast Asia, including several optimization projects.
China
In China, where we recently supplied our equipment to one of our clients’ geothermal projects, the National Energy Administration adopted the 13th Renewable Energy Development Five Year Plan. The Governmentplan was adopted in December 2016 and establishes targets for renewable energy deployment until 2020. Key objectives under the plan include, among others, to increase the share of Indonesia announced its intentionnon-fossil fuel energy in total primary energy consumption to reduce the country’s carbon dioxide emissions by 26%15% by 2020 at the 2009 United Nations Climate Change Conference in Copenhagen and during 2015 in Paris.to 20% by 2030, and to increase installed renewable power capacity to 680 GW by 2020.
East Africa
In East Africa the geothermal potential along the Rift Valley is estimated at several thousand MW. The different countries along the Rift Valley are at different stages of development of their respective geothermal potentials.
In Kenya, there are already several geothermal power plants, including the only geothermal IPP in Africa, our 139 MW Olkaria III complex. The Government of KenyaKenyan government has identified the country's untapped geothermal potential as the most suitable indigenous source of electricity and it aspires to reach 5,000 MW5 GW of geothermal power generation by 2030. To attain such number,this goal, GDC was formed to fast track the development of geothermal resources in Kenya. Ormat has asWe have a 51% interest in a consortium that signed a PPA for a 35 MW geothermal power plant in the Menengai area.
The Government of KenyaKenyan government is aiming to reach 22.7GW of power generating capacity by 2033, under the Least-Cost Power Development Plan 2013-33 with a target of 42% of such capacity generated from renewable energy sources (including large hydro but excluding solar).
In December 2012, FITs for various technologies were reviewed and the process of negotiating PPAs in Kenya streamlined. Projects underGeothermal projects subject to this mechanismregime have priority grid access at the cost of the developer. Geothermal projects from 35 MW to 70 MW have a USD $0.088 per kWh (up to 500MW)500 MW) FIT.
In 2015, the Departmental Committee of Finance,Finance, Planning, and Trade amended the Income Tax Act in view of the 2015 Finance Bill. The amendments include maintaining the enhanced investment deduction of 150% under section 17B and extending the period of deduction of tax losses to over 10 years.
The governments of Djibouti, Ethiopia, Eritrea,, Tanzania, Uganda, Rwanda and Zambia are exploring ways to develop geothermal resources in their countries, mostly through the help of international development organizations such as the World Bank.
In Ethiopia, the new Geothermal Law Proclamation 981 became effective in 2016, and supporting regulations are under consideration. We hold rights for four concessions in Ethiopia. We are currently negotiating a power purchase agreement with the local government and we have started initial exploration studies on the secured concessions.
In January 2014, energy ministers and delegates from 19 countries committed to the creation of the Africa Clean Energy Corridor Initiative (Corridor), at a meeting in Abu Dhabi convened by the International Renewable Energy Agency. The Corridor will boost the deployment of renewable energy and aim to help meet Africa’s rising energy demand with clean, indigenous, cost-effective power from sources including hydro, geothermal, biomass, wind and solar.
East Africa and South East Asia may benefit from two initiatives announced by President Obama. In June 2013, the Power Africa initiative was announced, which contemplated that the U.S. would invest up to $7.0 billion in sub-Saharan Africa over the ensuing five years with the aim of doubling access to power. The program will partner the U.S. government with the governments of six sub-Saharan countries, among them Kenya, Ethiopia and Tanzania, that have the potential for geothermal energy development. In 2012, President Obama proposed the U.S. Asia Pacific Comprehensive Energy Partnership that encourages U.S. companies to develop renewable energy in South East Asian countries, including Indonesia. The U.S. will provide up to $6.0 billion to support the Partnership. However, with the recent election of president Trump, the progress of these initiatives is uncertain
Other opportunities
Recovered Energy Generation
In addition to our geothermal power generation activities, we are pursuing recovered energy-based power generation opportunities in North America and the rest of the world. We believe recovered energy-based power generation will ultimately benefit from the efforts to reduce greenhouse gasGHG emissions. For example, in the U.S., FERC has expressed its position that one of the goals of new natural gas pipeline design should be to facilitate the efficient, low-cost transportation of fuel through the use of waste heat (recovered energy) from combustion turbines or reciprocating engines that drive station compressors to generate electricity for use at compressor stations or for commercial sale. FERC has, as a matter of policy, requested natural gas pipeline operators filing for a certificate of approval for new pipeline construction or expansion projects to examine “opportunities to enhance efficiencies for any energy consumption processes in the development and operation” of the new pipeline. We have built over 2122 power plants which generate electricity fromutilizing “waste heat” from gas turbine-driven compressor stations along interstate natural gas pipelines, from midstream gas processing facilities, and from processing industries in general.
Several states, and to a certain extent, the federal government, have recognized the environmental benefits of recovered energy-based power generation. For example, 18 states currently allow electric utilities to include recovered energy-based power generation in calculating such utilities' compliance with their mandatory or voluntary RPS and/or Energy Efficient Resources Standards. In addition, California modified the Self GenerationGeneration Incentive Program which allowsto allow recovered energy-based power generation to qualify for a per watt incentive.
In 2012, the Governor
In addition, in Colorado, the state PUC ruled that Xcel Energy, the largest utility in Colorado, will begin offeringthat state, now offers a $500 per kW incentive for recycled energy projects. The This incentive will beis paid out over 10 years to developers and manufacturers who convert waste heat from stacks and process it into electricity. Xcel Energy has developed aThe tariff to providedetails the rates and a methodology for recycled energy projects that wish to take advantage of this incentive.
At the Federal level, under the Clean Power Plan, waste-heat-to-power (recovered energy) is an eligible technology that can be implemented by states as a means to comply with their Clean Power Plan emissions reduction targets. The inclusion of waste-heat-to-power as an eligible technology under the Clean Power Plan could potentially create demand for REG in states that have good waste-heat resources, but that so far had no policies in place, like an RPS, to create demand for renewables. However, there is now great uncertainty at the Federal level whether the current administration will keep the Clean Power Plan and its emissions reduction targets and strategies in place. The U.S. Court of Appeals for the District of Columbia Circuit heard oral arguments in the cases challenging the Clean Power Plan on September 27, 2016. The court has not issued its decision, and it remains unclear exactly what action the Trump Administration will take, although the Trump Administration has expressed its desire to eliminate the Clean Power Plan and general skepticism of climate change.
Recovery of waste heat is also considered “environmentally friendly” in the western Canadian provinces. On November 22, 2015, the Alberta Government of Alberta released the Clean Leadership Plan that includes (a) phasing out of coal-fired electricity generation by 2030; (b) a commitment to generate 30 percent of Alberta’sAlberta’s electricity from renewable sources by 2030; (c) new financing for energy efficiency; and (d) an economy-wide price on carbon pollution. The plan also includes mandatingmandates that Alberta to reduce methane emissions from oil and gas operations by 45% by 2025. In 2016, the Canadian government ratified its commitments in the Paris Agreement, which features a commitment to reduce emissions by 30% from 2005 levels by 2030. The federal government has announced that Canadian provinces must have an emission reduction plan in place or be subject to a federal carbon tax in 2018. This comprehensive set of climate policies, once fully implemented, will encourage the development of renewable energy technologies, including waste heat recovery, in Alberta.Alberta and other provinces. We believe that Europe and other markets worldwide may offer similar opportunities in recovered energy-based power generation.
In summary, the market for the recovery of waste heat converted into electricity exists either when the already available electricity is expensive or where the regulatory environment facilitates construction and marketing of power generated from recovered waste heat. However, such projects tend to be smaller than 9 MW and we expect theany growth to be relatively slow and geographically scattered.
New activities under our strategic plan
The traditional grid is undergoing a major disruption. The continued decline in Solar PV prices is impacting renewable energy pricing and the growth in intermittent green energy is generating increasing strains on the grid, mainly in the U.S and Europe. The increasing amount of solarSolar PV power being supplied to the grid can create situations where a significant amount of power plant capacity must be available to ramp up and down to accommodate solarSolar PV daily output cycles and variations due to atmospheric conditions. The output from Solar PV power plants can change significantly over short periods of time due to environmental conditions like cloud movement and fog burn off and that can cause instability on the electric grid.
As a result, energy management and specifically electricity storage is becoming a key component of the future grid. In parallel, we see movement of C&I and communities toward direct purchases of electricity
and an increased focus on reliability of electricity supply.
Energy Storage
Energy storage systems utilize low cost, surplus, available electricity that enables utilities to optimize the operation of the grid and generators to run closer to full capacity for longer periods of time and operate more efficiently and effectively. With the increasing use of wind and solar energy, the need for storage services such as balancing services, frequency regulation, rapid generation ramping, reactive power, black start and movement of energy from times of excess to times of high demand is becoming more important.
The global energy storage market is still developing, with specific applications and geographies leading the overall market. After a record-breaking year in 2015, the energy battery storage industry is continuing to gain momentum globally. More than 1.6 GW of new deployments (approximately $2.0 billion) were announced worldwide in 2015. Various diversified battery storage technologies have been developed and deployed. According to GTM, total deployed MW in 2016 and 2017 represent continued growth of above 25% per year and forecasts for 2018 and beyond expect greater growth to be achieved as energy storage becomes cheaper and its technologies and markets more mature.
Much of the BESS activity is focused on energy storage for the grid and ancillary services. Behind the meter deployments are growing fast to enable customers to increase savings from demand charge reductions and create revenues through active market participation (demand response programs). Also, grids/grids and utilities are undergoing significant changes such as grid aging, grid congestion, coal retirement, implementation of carbon reduction rules and increasing renewable energy and intermittent energy penetration. BESS delivers many benefits to grids and end users (behind the customer meter, as well as to micro-grids). Real-time balancing services can reactively increase stability and reliability on the grid to offset renewables inherent flexibility, to store energy now to be used later and to promote business resiliency, power quality and physically distributed benefits for all segments of the grid or the end customer.
According to Navigant research, BESS continues to be one of the fastest growing segments of the broader energy industry, set to reach an overall installed power capacity of 143.7 GW and a cumulative global market size of $162.3 billion in the next 10-year period. This represents a CAGR of approximately 30% over the 10-year period in both in-front-of-the meter grid connected and behind-the-meter commercial and industrialC&I deployments.
According to a Green Tech Media (GTM) GTM report from December 2016, the U.S. behind-the-meter energy storage market today is small, with combined residential and non-residential deployments in 2015 accounting for only 15% of installed capacity in MW terms. By 2021, however, the behind-the-meter segment willis expected to account for half of the annual U.S. market, driven by a plethora ofmany factors including improved system economics, net-energy metering reform, changes to utility rate structures, increasing viability of demand-charge management for non-residential customers, and increased interest in reliability and resiliency. GTM is expecting a total installations of more than 4 GW untilthrough 2021 in the U.S. These trends in the U.S. market are expected to be seenexperienced in other leading global markets in Europe Asia and the Far East. Asia.
Following the closing ofWe Viridity’s acquisition we will own substantially all of VEI’s business and assets and we plan to use the VEIour Viridity platform and services to expand our market presence in the energy storage market and further develop VEI’s demand responseour VPower™ software platform to be utilized in optimizing and energy storage services.generating revenues from demand response including ownership and supply of BESS systems. We expect that togetherthe eco system we have created, combining our Viridity business’s capabilities with our global presence, experience in technology and system integration, andEPC capabilities, flexible business models and our reputation and experience in the geothermal and recovered energy sectors, we canwill enable us to expand into this growing sector.
C&I
The C&I sector is shifting from centralized electricity generation systems to distributed resources supported by emerging models of direct PPAs with renewable power plants, on-site deployments, and customized solutions tofor energy management. Participants in the C&I sector are motivated to purchase renewable energy to reduce costs and diversify their energy supply, to lock in long-term energy price stability and carbon footprint reductions, to achieve renewable energy targets and to demonstrate leadership, innovation, and competitive first mover advantages. Ormat seesWe see C&I customers as a natural expansion of our customer base from regulated utilities to medium and large C&I clientscustomers desiring to contract for renewable energy.
The advances in electricity storage technology together with high period demand charges, demand response programs, concern over electricity supply reliability and more aggressive goals for renewable energy content than those of centralized electricity suppliers are all factors that have supported the growth of the C&I market. The need for technical customized solutions to meet these varied C&I needs fits well with the expected acquisition of VEI’sour Viridity business and assets and our experience in providing customized geothermal and REG solutions to various customers around the world.
Solar PV
The market for Solar PV power grew significantly in recent years, driven by a combination of favorable government policies and a decline in equipment prices. We are monitoring market drivers with the potential to develop Solar PV power plants in locations where we can offer competitively priced power generation. Our focus currently is on large-scale solar power plant development opportunities worldwide such as in: (i) Chile, where the total installed Solar PV capacity increased from 6 MW in 2013 to almost 1 GW by the end of 2015 and is currently considered the cheapest source of electricity in the country, (ii) Mexico, considered among the largest potential national markets in Latin America on the strength of high solar resources and recent energy market reform, (iii) India, where the central government recently gave its approval to ramp up India’s solar power capacity target to achieve 100 GW by 2022 (60 GW of grid connected solar power projects and 40 GW of rooftop solar) and (iv) the East Africa region, where a considerable amount of solar radiation and abundant available land constitute significant solar potential. Governments in the East Africa region have introduced various solar targets and incentives, which provide opportunities for installing grid-tied and off-grid Solar PV systems in some of our operating geothermal power plants to displace fuel costs.reduce internal consumption loads. We are planning to install the first system in Tungsten Mountain. In addition, we are looking for hybrid projects that involve intermittent power (such as Solar PV) and energy storage.
Competitive Strengths
Competitive Assets. We believe our assets are competitive for the following reasons:
| Contracted Generation. All of the electricity generated by our geothermal power plants is currently sold pursuant to long-term PPAs with an average remaining life of approximately |
| Baseload Generation. All of our geothermal power plants supply all or a part of the baseload capacity of the electric system in their respective markets. This means they supply electric power on an around-the-clock basis. This provides us with a competitive advantage over other renewable energy sources, such as wind power, solar power or hydro-electric power (to the extent |
| Ancillary Services. Geothermal power plants positively impact electrical grid stability and provide valuable ancillary services. Because of the baseload nature of their output, they have high transmission utilization efficiency, provide capacity, provide grid inertia and reduce the need for ancillary services such as voltage regulation, reserves and flexible capacity. Other intermittent renewables create integration costs, |
Competitive Pricing. Geothermal power plants, while site specific, are economically feasible in many locations, and the electricity they generate is generally price competitive under existing economic conditions and existing tax and regulatory regimes compared to electricity generated from fossil fuels or other renewable sources in many places around the world. Geothermal energy is recognized as one of the lower cost sources of energy from a LCOE perspective.
Ability to Finance Our Activities from Internally Generated Cash Flow. The cash flow generated by our portfolio of operating geothermal and REG power plants provides us with a robust and predictable base for certain exploration, development, and construction activities. We plan to evaluate various alternatives for financing the expansion of our business as we further develop and implement our new strategic plan.
Growing Legislative Demand for Environmentally-Friendly Renewable Resource Assets. Most of our currently operating power plants produce electricity from geothermal energy sources. The clean and sustainable characteristics of geothermal energy give us a competitive advantage over fossil fuel-based electricity generation as countries increasingly seek to balance environmental concerns with demands for reliable sources of electricity.
High Efficiency from Vertical Integration. Unlike our competitors in the geothermal industry, we are a fully integrated geothermal equipment, services, and power provider. We design, develop, and manufacture equipment that we use in our geothermal and REG power plants. Our intimate knowledge of the equipment that we use in our operations allows us to operate and maintain our power plants efficiently and to respond to operational issues in a timely and cost-efficient manner. Moreover, given the efficient communicationscommunication among our subsidiarysubsidiaries that designsdesign and manufacturesmanufacture the products we use in our operations and our subsidiaries that own and operate our power plants, we are able to quickly and cost effectively identify and repair mechanical issues and to have technical assistance and replacement parts available to us as and when needed.
Exploration and Drilling Capabilities. We have in-house capabilities to explore and develop geothermal resources and have established a drilling operation that currently owns nineseven drilling rigs. We employ an experienced resource group that includes engineers, geologists, and drillers, which executes our exploration and drilling plans for projects that we develop.
Highly Experienced Management Team. We have a highly qualified senior management team with extensive experience in the geothermal power sector.
Technological Innovation. We have 7377 U.S. patents in force (and have approximately 169 U.S. patents pending) relating to various processes and renewable resource technologies. All of our patents are internally developed. Our ability to draw upon internal resources from various disciplines related to the geothermal power sector, such as geological expertise relating to reservoir management, and equipment engineering relating to power units, allows us to be innovative in creating new technologies and technological solutions.
Limited Exposure to Fuel Price Risk. A geothermal power plant does not need to purchase fuel (such as coal, natural gas, or fuel oil) in order to generate electricity. Thus, once the geothermal reservoir has been identified and estimated to be sufficient for use in a geothermal power plant, the drilling of wells is complete, and the plant has a PPA, the plant is not exposed to fuel price or fuel delivery risk apart from the impact fuel prices may have on the price at which we sell power under PPAs that are based on the relevant power purchaser’s avoided costs.
Although we are confident in our competitive position in light of the strengths described above, we face various challenges in the course of our business operations, including as a result of the risks described in Item 1A — “Risk Factors” below, the trends and uncertainties discussed in “Trends and Uncertainties” under Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” below, and the competition we face in our different business segments described under “Competition” below.
Business Strategy
Our strategy is to continue building a geographically balanced portfolio of geothermal and recovered energy assets, and to continue to be a leader in the geothermal energy market with the objective of becoming a leading global provider of renewable energy. Since 2015, we have begun to implemented a number of the elements of a new multi-year strategic plan. We expect the plan to evolve over time in response to market conditions and other factors. We intend to implement this strategy through:
• | Development and Construction of New Geothermal Power Plants — continuously seeking out commercially exploitable geothermal resources, developing and constructing new geothermal power plants and entering into long-term PPAs providing stable cash flows in jurisdictions where the regulatory, tax and business environments encourage or provide incentives for such |
• | Expanding our |
• | Acquisition of New Assets — expanding and accelerating growth through acquisition activities globally, aiming to acquire from third parties additional geothermal assets, such as our recent announcement that we signed an agreement to acquire U.S. Geothermal Inc., which owns approximately 38 MW of operating power plants, and |
• | Manufacturing and Providing Products and EPC Services Related to Renewable Energy — designing, manufacturing and contracting power plants for our own use and selling to third parties power units and other generation equipment for geothermal and recovered energy-based electricity |
• | Expanding into New Technologies |
• | Expand our |
• | Increasing Output from Our Existing Power Plants— increasing output from our existing geothermal power plants by adding additional generating capacity, upgrading plant technology, and improving geothermal reservoir operations, including improving methods of heat source supply and |
• | Cost |
• | Technological Expertise — investing in research and development of renewable energy technologies and leveraging our technological expertise to continuously improve power plant components, reduce operations and maintenance costs, develop competitive and environmentally friendly products for electricity generation and target new service opportunities. |
Recent Developments
The most significant recent developments in our company and business are described below.
● | On January 24, 2018, we announced that we entered into a definitive agreement to acquire U.S. Geothermal Inc. (NYSE American: HTM), a renewable energy company focused on the development, production and sale of electricity from geothermal energy. Under the terms of the merger agreement, holders of U.S. Geothermal common stock will receive $5.45 per share in cash. On a fully diluted basis, including payment to U.S. Geothermal’s option holders, we expect to pay total consideration of approximately $109.9 million from our corporate funds. The closing of the merger is subject to customary conditions, including receipt of regulatory approvals and approval by holders of a majority of the outstanding shares of US Geothermal’s common stock. The transaction is expected to close in the second quarter of 2018. | |
U.S. Geothermal is currently operating geothermal power projects at Neal Hot Springs, Oregon, San Emidio, Nevada and Raft River, Idaho for a total designed net output of 45 MW that currently generate approximately 38 MW net. In |
● | On December 13, 2017, we |
● | On |
● | On October 10, 2017, we announced that the second unit of the Sarulla geothermal power plant located in the North Sumatra region of Indonesia, one of the world’s largest geothermal power plants, commenced commercial operation. The Sarulla power plant includes three units of approximately 110 MW each, utilizing both steam and brine extracted from the geothermal field to increase the power plant’s efficiency. The first unit of the power plant commenced commercial operation on |
● | On September 26, 2017, we announced that the 35 MW Platanares geothermal project in Honduras commenced commercial operation. We had previously signed a BOT contract for the Platanares geothermal project in Honduras with ELCOSA, a privately-owned Honduran energy company, for 15 years from COD. The Platanares power plant sells its power under a 30-year PPA with ENEE. We hold a portion of the land on which the power plant is located through a lease from a local municipality. Because the term of the lease exceeds the term in office of the relevant municipal government, the lease remains subject to the additional approval of the Honduran Congress in order to be fully valid. We have commenced the necessary steps to obtain such approval but the current elections in Honduras may result in a delay in obtaining such approval. The project is expected to generate average annual revenue of approximately $33 million. |
● | On July 26, 2017, we announced that ORIX closed its acquisition of approximately 11 million shares of our common stock, representing an approximately 22% ownership stake in the Company, from FIMI ENRG Limited Partnership, FIMI ENRG, L.P., Bronicki Investments, Ltd. and certain senior members of our management team pursuant to a stock purchase agreement entered into by ORIX and the selling stockholders on May 4, 2017. In connection with the acquisition, on May 4, 2017, we entered into certain related agreements with ORIX, including a |
Under the Governance Agreement, ORIX has the right to designate three persons to our Board, which was expanded to nine directors, and propose a fourth person to be mutually agreed by the Company and ORIX to serve as a new independent director on our Board. In addition, for so long as ORIX is entitled to Board representation pursuant to the Governance Agreement, ORIX will be subject to certain customary standstill restrictions, including an effective 25% cap on its voting rights. Pursuant to the RRA, ORIX also has certain customary registration rights with respect to the shares of our common stock that it owns. | ||
Under the CCA, we have exclusive rights to develop, own, operate and provide equipment for ORIX geothermal energy projects in all markets outside of Japan. In addition, we have certain rights to serve as technical partner and co-invest in ORIX geothermal energy projects in Japan. ORIX will also assist us in obtaining project financing for our geothermal projects from a variety of leading providers of renewable energy debt financing with which ORIX has relationships in Asia and around the | ||
● | On June 1, 2017, we announced that SCPPA received the final necessary approval from the City of Los Angeles that enabled SCPPA to execute the ONGP Portfolio PPA. Under the ONGP Portfolio PPA, SCPPA will purchase 150 MW of power generated by a portfolio of our new and | |
The ONGP Portfolio PPA covers nine of |
● | On March 15, 2017, we announced that we completed the acquisition of our Viridity business. At closing, we paid initial consideration of $35.3 million. Additional contingent consideration may be payable upon the achievement of certain performance milestones measured at the end of fiscal year 2020. This transaction |
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Pursuant to the terms of an Amended and Restated Investment Agreement (Investment Agreement) and Shareholders Agreement with Sageos Holding (Sageos), a wholly owned subsidiary of Bureau de Recherches Géologiques et Minières (BRGM), Ormat together with Caisse des Dépôts et Consignations (CDC), a French state-owned financial organization, acquired an approximately 80% interest in GB allocated 75% to Ormat and 25% to CDC. Ormat and CDC will gradually increase their combined interest in GB to 85% and Sageos will hold the remaining balance.
Pursuant to the agreements, we paid approximately $20.6 million (approximately €18.5 million) to Sageos for approximately 60% interest in GB. In addition, we are committed to further invest $8.4 million (approximately €7.5 million) by July 2018, which will increase our interest to 63.75%. The cash will be used mainly for the enhancement of the power plant.
We have planned modifications to the existing equipment as well as to further develop the asset, with a potential of reaching a total of 45 MW in phased development by 2021. Under the Investment Agreement, we will pay Sageos an additional amount of up to $13.4 million (approx. €12 million) subject to the achievement of agreed production thresholds and capacity expansion within a defined time period.
Bouillante power plant sells its electricity under a 15-year PPA that was entered into in February 2016 with Électricité de France S.A. (EDF), the French electric utility. We plan to optimize the use of the resource at the existing facilities and recover its current production to its design capacity of 14.75 MW by mid-2017. Upon completion of the enhancement, the plant is expected to generate approximately $22.3 million (approximately €20 million) of annual revenues.
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Operations of our Electricity Segment
How We Own Our Power Plants. We customarily establish a separate subsidiary to own interests in each of our power plant. Our purpose in establishing a separate subsidiary for each plant is to ensureplants. This ensures that the power plant, and the revenues generated by it, will be the only source for repaying indebtedness, if any, incurred to finance the construction or the acquisition (or to refinance the construction or acquisition) of the relevant power plant. If we do not own all of the interest in a power plant, we enter into a shareholdersshareholders’ agreement or a partnership agreement that governs the management of the specific subsidiary and our relationship with our partner in connection with the specific power plant. Our ability to transfer or sell our interestinterests in certain power plants may be restricted by certain purchase options or rights of first refusal in favor of our power plant partners or the power plant’s power purchasers and/or certain change of control and assignment restrictions in the underlying power plant and financing documents. All of our domestic geothermal and REG power plants are Qualifying Facilities under the PURPA and are eligible for regulatory exemptions from most provisions of the FPA and certain state laws and regulations.
How We Explore and Evaluate Geothermal Resources. Since 2006, we have expanded our exploration activities, initially in the U.S. and more recentlyin the last few years with an increasing focus internationally. 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 and determine to pursue its development. Exploration activities generally involve the phases described below.
Initial Evaluation. Identifying and evaluating potential geothermal resources by sampling and studying new areas combined with information available from public and private sources. We generally adhere to the following process, although our process can vary from site to site depending on geological circumstances and prior evaluation:
We evaluate historic, geologic and geothermal information available from public and private databases, including geothermal, mining, petroleum and academic sources.
We visit sites, sampling fluids for chemistry if necessary, to evaluate geologic conditions.
We evaluate available data, and rank prospects in a database according to estimated size and perceived risk. For example, pre-drilled sites with extensive data are considered lower risk than “green field” sites. Both prospect types are considered critical for Ormat’sour continued growth.
We generally create a digital, spatial geographic information systems (GIS) database and 3D geologic model containing all pertinent information, including thermal water temperature gradients derived from historic drilling, geologic mapping information (e.g., formations, structure, alteration, and topography), and any available archival information about the geophysical properties of the potential resource.
We assess other relevant information, such as infrastructure (e.g., roads and electric transmission lines), natural features (e.g., springs and lakes), and man-made features (e.g., old mines and wells).
Our initial evaluation is usually conducted by our own staff, although we might engage outside service providers for some tasks from time to time. The costs associated with an initial evaluation vary from site to site, based on various factors, including the acreage involved and the costs, if any, of obtaining information from private databases or other sources. On average, our expenses for an initial evaluation range from approximately $10,000 to $50,000 including travel, chemical analyses, and data acquisition.
If we conclude, based on the information considered in the initial evaluation, that the geothermal resource could support a commercially viable power plant, taking into account various factors described below, we proceed to land rights acquisition.
Land Acquisition. Acquiring land rights to any geothermal resources our initial evaluation indicates could potentially support a commercially viable power plant, taking into account various factors. For domestic power plants, we either lease or own the sites on which our power plants are located. For our foreign power plants, our lease rights for the power plant site are generally contained in the terms of a concession agreement or other contract with the host government or an agency thereof. In certain cases, we also enter into one or more geothermal resource leases (or subleases) or a concession or an option agreement or other agreement granting us the exclusive right to extract geothermal resources from specified areas of land, with the owners (or sublessors) of such land. In some cases, we first obtain first the exploration license and once certain investment requirements are met, we can obtain the geothermal exploitation rights. This usually gives us the right to explore, develop, operate, and maintain the geothermal field, including, among other things, the right to drill wells (and if there are existing wells in the area, to alter them) and build pipelines for transmitting geothermal fluid. In certain cases, the holder of rights in the geothermal resource is a governmental entity and in other cases a private entity. Usually the duration of the lease (or sublease) and concession agreement corresponds to the duration of the relevant PPA, if any. In certain other cases, we own the land where the geothermal resource is located, in which case there are no restrictions on its utilization. Leasehold interests in federal land in the U.S. are regulated by the BLM and the Minerals Management Service. These agencies have rules governing the geothermal leasing process as discussed below under “Description of Our Leases and Lands”.
For most of our current exploration sites in the U.S., we acquire rights to use the geothermal resource through land leases with the BLM, with various states, or through private leases. Under these leases, we typically pay an up-front non-refundable bonus payment, which is a component of the competitive lease process. In addition, we undertake to pay nominal, fixed annual rent payments for the period from the commencement of the lease through the completion of construction. Upon the commencement of power generation, we begin to pay to the lessors long-term royalty payments based on the use of the geothermal resources as defined in the respective agreements. These payments are contingent on the power plant’splant’s revenues. A summary of our typical lease terms is provided below under “Description of our Leases and Lands”.
The up-front bonus and royalty payments vary from site to site and are based on, among other things, on current market conditions.
Surveys. Conducting geological, geochemical, and/or geophysical surveys on the sites acquired. Following the acquisition of land rights for a potential geothermal resource, we conduct additional surface water analyses, soil surveys, and geologic mapping to determine proximity to possible heat flow anomalies and up-flow/permeable zones. We augment our digital database with the results of those analyses and create conceptual and digital geologic models to describe geothermal system controls. We then initiate a suite of geophysical surveys (e.g., gravity, magnetics, resistivity, magnetotellurics, reflection seismic, LiDAR, and spectral surveys) to assess surface and sub-surface structure (e.g., faults and fractures) and improve the geologic model of fluid-flow conduits and permeability controls. All pertinent geological and geophysical data are used to create three-dimensional geologic models to identify drill locations. These surveys are conducted incrementally considering relative impact and cost, and the geologic model is updated continuously.
We make a further determination of the commercial viability of the geothermal resource based on the results of this process, particularly the results of the geochemical surveys estimating temperature and the overall geologic model, including potential resource size. If the results from the geochemical surveys are poor (i.e., low derived resource temperatures or poor permeability) or the geologic model indicates small or deep resource, we re-evaluate the commercial viability of the geothermal resource and may not proceed to exploratory drilling. We generally only move forward with those sites that we believe have a high probability forof successful development.
Exploratory Drilling. Drilling one or more exploratory wells on the high priority, relatively low risk sites to confirm and/or define the geothermal resource. If we proceed to exploratory drilling, we generally use outside contractors to create access roads to drilling sites and related activities. We have continued efforts to reduce exploration costs and therefore, after obtaining drilling permits, we generally drill temperature gradient holes and/or core holes that are lower cost than slim holes (used in the past) using either our own drilling equipment, whenever possible, or outside contractors. If the obtained data supports a conclusion that the geothermal resource can support a commercially viable power plant, it will be used as an observation well to monitor and define the geothermal resource. If the core hole indicates low temperatures or does not support the geologic model of anticipated permeability, it may be plugged, and the area reclaimed. In undrilled sites, we typically step up from shallow (500-1000 ft)feet) to deeper (2000-4000 ft)feet) wells as confidence improves. Following proven temperature in core wells, we typically move to slim and/or fullfull- size wells to quantify permeability.
Each year we determine and approve an exploration budget for the entire exploration activity in such year. We prioritize budget allocation between the various geothermal sites based on commercial and geological factors. The costs we incur for exploratory drilling vary from site to site based on various factors, including the accessibility of the drill site, the geology of the site, and the depth of the resource. However, on average, exploration costs, prior to drilling of a full-size well are approximately $1.0 million to $3.0 million for each site, not including land acquisition. However, we only reach such spending levels for sites that proved to be successful in the early stages of the exploration.
At various points during our exploration activities, we re-assess whether the geothermal resource involved will support a commercially viable power plant based on information available at that time. Among other things, we consider the following factors:
New data and interpretations obtained concerning the geothermal resource as our exploration activities proceed, and particularly the expected MW capacity power plant the resource can be expected to support. The MW capacity can be estimated using analogous systems and/or quantitative heat in place estimates until results from drilling and flow tests quantify temperature, permeability, and resulting resource size.
Current and expected market conditions and rates for contracted and merchant electric power in the market(s) to be serviced.
Availability of transmission capacity.
Anticipated costs associated with further exploration activities and the relative risk of failure.
Anticipated costs for design and construction of a power plant at the site.
Anticipated costs for operation of a power plant at the site, particularly taking into account the ability to share certain types of costs (such as control rooms) with one or more other power plants that are, or are expected to be, operating near the site.
If we conclude that the geothermal resource involved will support a commercially viable power plant, we proceed to constructing a power plant at the site.
How We Construct Our Power Plants. The principal phases involved in constructing one of our geothermal power plants are as follows:
Drilling production and injection wells.
Designing the well field, power plant, equipment, controls, and transmission facilities.
Obtaining any required permits, electrical interconnection and transmission agreements.
Manufacturing (or in the case of equipment we do not manufacture ourselves, purchasing) the equipment required for the power plant.
Assembling and constructing the well field, power plant, transmission facilities, and related facilities.
It generally In recent years, it takes approximately twothree years from the time we drill a production well, until the power plant becomes operational.
Drilling Production and Injection Wells. We consider completing the drilling of the first production well asto be the beginning of our construction phase for a power plant. However, itthis is not always sufficient for a full release for construction. The number of production wells varies from plant to plant depending on, among other things, on the geothermal resource, the projected capacity of the power plant, the power generation equipment to be used and the way geothermal fluids will be re-injected through injection wells to maintain the geothermal resource and surface conditions. We generally drill the wells ourselves although in some cases we use outside contractors.
The cost for each production and injection well varies depending on, among other things, on the depth and size of the well and market conditions affecting the supply and demand for drilling equipment, labor and operators. OurIn the last five years, our typical cost for each production and injection well is approximately $4.0$3.3 million with a range of $1.0 million to $10.0$13.0 million.
Design. We use our own employees to design the well field and the power plant, including equipment that we manufacture and that will be needed for the power plant. The designs vary based on various factors, including local laws, required permits, the geothermal resource, the expected capacity of the power plant and the way geothermal fluids will be re-injected to maintain the geothermal resource and surface conditions.
Permits. We use our own employees and outside consultants to obtain any required permits and licenses for our power plants that are not already covered by the terms of our site leases. The permits and licenses required vary from site to site, and are described below under “Environmental Permits”.
Manufacturing. Generally, we manufacture most of the power generating unit equipment we use at our power plants. Multiple sources of supply are generally available for all other equipment we do not manufacture.
Construction. We use our own employees to manage the construction work. For site grading, civil, mechanical, and electrical work we use subcontractors.
During fiscal year 2016,2017, in the Electricity segment, we focused on the commencement of operations at Olkaria IIIPlatanares power plant 4.in Honduras and Tungsten Mountain in Nevada. We continuedbegan with construction of the Platanares projectOlkaria III plant expansion in HondurasKenya and began constructionenhancement work in some of our operating power plants. During fiscal year 2016, we focused on the Tungsten and Dixie Meadows projects in Nevada.commencement of operations at Olkaria III plant 4. During fiscal year 2015, we focused on the commencement of operations at the McGinness Hills phase 2 and the Don A. Campbell phase 2 power plants. We continued with construction of Olkaria III plant 4. During fiscal year 2014, we began construction of the Don A. Campbell phase 2 power plant and Olkaria III plant 4.
When deciding whether to continue holding lease rights and/or to pursue exploration activity, we diligently prioritize our prospective investments, taking into account resource and probability assessments in order to make informed decisions about whether a particular project will support commercial operations.operation. As a result, during fiscal year 2017 we discontinued exploration activities at four prospective sites: the Ungaran region in Indonesia, Glass Buttes - Midnight Point in Oregon and Tuscarora - phase 2 and Don A. Campbell - phase 3, in Nevada. During fiscal year 2016, we discontinued exploration activities at three future prospects, includingprospective sites, in the Kula region in Hawaii and the Aqua quietaQuieta and sollipulliSollipulli regions in Chile. During fiscal year 2015, we discontinued exploration and development activities at ten future prospects, including Kona and Ulupalakua (Maui) in Hawaii, Warm Springs Tribe and Newberry - Twilight in Oregon, Whirlwind Valley in Utah, Argenta, Hycroft and South Jersey in Nevada and Mariman and Quinohuen in Chile. During fiscal year 2014, we discontinued exploration and development activities at seven exploration sites and one development project, including Huu Dumpo in Indonesia, Mount Spurr in Alaska, San Pablo, San Jose II, and Aroma in Chile, Silver Lake, Summer Lake and Foley Hot Springs in Oregon and Wister in California.
After conducting exploratory studies at those sites, we concluded that the respective geothermal resources would not support commercial operations. Costs associated with exploration activities at these sites were expensed accordingly (see “Write-off of Unsuccessful Exploration Activities” under Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations”).
We added to our exploration activities inventory two prospective sites in 2017 and ten prospective sites in each of the years ended December 31, 2016 and 2015 and four sites during the years ended December 31, 2014.2015.
How We Operate and Maintain Our Power Plants. In the U.S. we usually employ, our wholly owned subsidiary, Ormat Nevada, to actusually acts as the operator of our power plants pursuant to the terms of an operation and maintenance agreement. Operation and maintenance of our foreign projects are generally provided by our subsidiary that owns the relevant project. Our operations and maintenance practices are designed to minimize operating costs without compromising safety or environmental standards while maximizing plant flexibility and maintaining high reliability. Our operations and maintenance practices for geothermal power plants seek to preserve the sustainable characteristics of the geothermal resources we use to produce electricity and maintain steady-state operations within the constraints of those resources reflected in our relevant geologic and hydrologic studies. Our approach to plant management emphasizes the operational autonomy of our individual plant or complex managers and staff to identify and resolve operations and maintenance issues at their respective power plants; however, each power plant or complex draws upon our available collective resources and experience, and that of our subsidiaries. We have organized our operations such that inventories, maintenance, backup, and other operational functions are pooled within each power plant complex and provided by one operation and maintenance provider. This approach enables us to realize cost savings and enhances our ability to meet our power plant availability goals.
Safety is a key area of concern to us. We believe that the most efficient and profitable performance of our power plants can only be accomplished within a safe working environment for our employees.employees. Our compensation and incentive program includes safety as a factor in evaluating our employees, and we have a well-developed reporting system to track safety and environmental incidents, if any, at our power plants.plants.
How We Sell Electricity. In the U.S., the purchasers of power from our power plants are typically investor-owned electric utility companies or electric cooperatives.cooperatives including public owned utilities. Outside of the U.S., the purchaser is either a state-owned utility or a privately-owned entity and we typically operate our facilities pursuant to rights granted to us by a governmental agency pursuant to a concession agreement. In each case, we enter into long-term contracts (typically, PPAs) for the sale of electricity or the conversion of geothermal resources into electricity. Although previously aour power plant’splants’ revenues under a PPA generally consisted of two payments, — energy payments and capacity payments, our recent PPAs provide for energy payments only. Energy payments are normally based on a power plant’s electrical output actually delivered to the purchaser measured in kilowatt hours,kWh, with payment rates either fixed or indexed to the power purchaser’s “avoided” power costs (i.e., the costs the power purchaser would have incurred itself had it produced the power it is purchasing from third parties) or rates that escalate at a predetermined percentage each year. Capacity payments are normally calculated based on the generating capacity or the declared capacity of a power plant available for delivery to the purchaser, regardless of the amount of electrical output actually produced or delivered. In addition, most of ourwe have six domestic power plants located in California, Nevada and Hawaii that are eligible for capacity bonus payments under the respective PPAs upon reaching certain levels of generation, or subject to a capacity payment reduction if certain levels of generation are not reached.
How We Finance Our Power Plants. Historically we have funded our power plants with a different sources of liquidity such as a combination of non-recourse or limited recourse debt, including lease financing, tax monetization transactions, internally generated cash, which includes funds from operation, as well as proceeds from loans under corporate credit facilities and the sale of securities,equity interests and sale of membership interests.other securities. Such leveraged financing permits the development of power plants with a limited amount of equity contributions, but also increases the risk that a reduction in revenues could adversely affect a particular power plant’s ability to meet its debt obligations. Leveraged financing also means that distributions of dividends or other distributions by our power plant subsidiaries to us are contingent on compliance with financial and other covenants contained in the applicable financing documents.
Non-recourse debt or lease financing refers to debt or lease arrangements involving debt repayments or lease payments that are made solely from the power plant’s revenues (rather than our revenues or revenues of any other power plant) and generally are secured by the power plant’s physical assets, major contracts and agreements, cash accounts and, in many cases, our ownership interest in our affiliate that owns that power plant. These forms of financing are referred to as “project financing”. Project financing transactions generally are structured so that all revenues of a power plant are deposited directly with a bank or other financial institution acting as escrow or security deposit agent. These funds are then payable in a specified order of priority set forth in the financing documents to ensure that, to the extent available, they are used to first pay operating expenses, senior debt service (including lease payments) and taxes, and to fund reserve accounts. Thereafter, subject to satisfying debt service coverage ratiosDSCR and certain other conditions, available funds may be disbursed for management fees or dividends or, where there are subordinated lenders, tofor the payment of subordinated debt service.
In the event of a foreclosure after a default, our affiliate that owns the power plant would only retain an interest in thepower plant assets, if any, remaining after all debts and obligations have been paid in full. In addition, incurrence of debt by a power plant may reduce the liquidity of our equity interest in that power plant because the equity interest is typically subject both to a pledge in favor of the power plant’splant’s lenders securing the power plant’s debt and to transfer and change of control restrictions set forth in the relevant financing agreements.
Limited recourse debt refers to project financing as described above with the addition of our agreement to undertake limited financial support for our affiliate that owns the power plant in the form of certain limited obligations and contingent liabilities. These obligations and contingent liabilities may take the form of guarantees of certain specified obligations, indemnities, capital infusions and agreements to pay certain debt service deficiencies. To the extent we become liable under such guarantees and other agreements in respect of a particular power plant, distributions received by us from other power plants and other sources of cash available to us may be required to be used to satisfy these obligations. Creditors of a project financing of a particular power plant may have direct recourse to us to the extent of these limited recourse obligations.
We have also used financing structures to monetize PTCs and depreciation, such as our recently announced Opalrecent tax equity partnership transaction and other favorable tax benefits derived from the financed power plantsinvolving Opal Geo, and an operating lease arrangement for our Puna complex power plants.
We have recentlyalso used a sale of membershipequity interests in two of our geothermal assets and nine of our REG facilities to fund corporate needs including fundsfunding for the construction of new projects. We may use suchof the same financing structure in the future.
How We Mitigate International Political Risk. We generally purchase insurance policies to cover our exposure to certain political risks involved in operating in developing countries, as described below under “Insurance”. To date, our political risk insurance policies are with the Multilateral Investment Guaranty Agency (MIGA),MIGA, a member of the World Bank Group, and Zurich Re, a private insurance and re-insurance company. Such insurance policies generally cover, subject to the limitations and restrictions contained therein, 80-90% of our losses resulting from a specified governmental actactions or responses thereto, such as confiscation, expropriation, riots, the inability to convert local currency into hard currency, and, in certain cases, the breach of agreements. We have obtained such insurance for the Olkaria, Zunil, Amatitlan, Platanares and Sarulla projects.
Description of Our Leases and Lands
We have domestic leases on approximately 320,800320,500 acres of federal, state, and private land in California, Hawaii, Nevada, New Mexico, Utah and Oregon. The approximate breakdown between federal, state and private leases and owned land is as follows:
85% are acresof the acreage under our control areis leased from the U.S. government, acting mainly through the BLM;
11% are leases withis leased or subleased from private landowners and/or leaseholders;
2% areis owned by us; and
the balance are leases with is leased from various states, none of which is currently material.
Each of the leases within each of the categoriesabove has standard terms and requirements, as summarized below. Internationally, our land position includes approximately 196,200122,500 acres, most of which are for geothermal prospects in Honduras and Indonesia.Honduras.
BLM Geothermal Leases
Certain of our domestic project subsidiaries have entered into geothermal resources leases with the U.S. government, pursuant to which they have obtained the right to conduct their geothermal development and operations on federally-owned land. These leases are made pursuant to the Geothermal Steam Act and the lessor under such leases is the U.S. government, acting through the BLM.
BLM geothermal leases grant the geothermal lessee the right and privilege to drill for, extract, produce, remove, utilize, sell, and dispose of geothermal resources on certain lands, together with the right to build and maintain necessary improvements thereon. The actual ownership of the geothermal resources and other minerals beneath the land is retained in the federal mineral estate. The geothermal lease does not grant to the geothermal lessee the exclusive right to develop the lands, although the geothermal lessee does hold the exclusive right to develop geothermal resources within the lands. The geothermal lessee does not have the right to develop minerals unassociated with geothermal production and cannot prohibit others from developing the minerals present in the lands. The BLM may grant multiple leases for the same lands and, when this occurs, each lessee is under a duty to not unreasonably interfere with the development rights of the other. Because BLM leases do not grant to the geothermal lessee the exclusive right to use the surface of the land, BLM may grant rights to others for activities that do not unreasonably interfere with the geothermal lessee’s uses of the same land; such other activities may include recreational use, off-road vehicles, and/or wind or solar energy developments.
Certain BLM leases issued before August 8, 2005 include covenants that require the projects to conduct their operations under the lease in a workmanlike manner and in accordance with all applicable laws and BLM directives and to take all mitigating actions required by the BLM to protect the surface of and the environment surrounding the land. Additionally, certain leases contain additional requirements, some of which concern the mitigation or avoidance of disturbance of any antiquities, cultural values or threatened or endangered plants or animals, the payment of royalties for timber, and the imposition of certain restrictions on residential development on the leased land.
BLM leases entered into after August 8, 2005 require the geothermal lessee to conduct operations in a manner that minimizes impacts to the land, air, water, to cultural, biological, visual, and other resources, and to other land uses or users. The BLM may require the geothermal lessee to perform special studies or inventories under guidelines prepared by the BLM. The BLM reserves the right to continue existing leases and to authorize future uses upon or in the leased lands, including the approval of easements or rights-of-way. Prior to disturbing the surface of the leased lands, the geothermal lessee must contact the BLM to be apprised of procedures to be followed and modifications or reclamation measures that may be necessary. Subject to BLM approval, geothermal lessees may enter into unit agreements to cooperatively develop a geothermal resource. The BLM reserves the right to specify rates of development and to require the geothermal lessee to commit to a communalization or unitization agreement if a common geothermal resource is at risk of being overdeveloped.
Typical BLM leases issued to geothermal lessees before August 8, 2005 have a primary term of ten years and will renew so long as geothermal resources are being produced or utilized in commercial quantities but cannot exceed a period of forty years after the end of the primary term. If at the end of the forty-year period geothermal steam is still being produced or utilized in commercial quantities and the lands are not needed for other purposes, the geothermal lessee will have a preferential right to renew the lease for a second forty-year term, under terms and conditions as the BLM deems appropriate.
BLM leases issued after August 8, 2005 have a primary term of ten years. If the geothermal lessee does not reach commercial production within the primary term, the BLM may grant two five-year extensions if the geothermal lessee: (i) satisfies certain minimum annual work requirements prescribed by the BLM for that lease, or (ii) makes minimum annual payments. Additionally, if the geothermal lessee is drilling a well for the purposes of commercial production, the primary term (as it may have been extended) may be extended for five years and as long thereafter as steam is being produced and used in commercial quantities (meaning the geothermal lessee either begins producing geothermal resources in commercial quantities or has a well capable of producing geothermal resources in commercial quantities and is making diligent efforts to utilize the resource) for thirty-five years. If, at the end of the extended thirty-five yearthirty-five-year term, geothermal steam is still being produced or utilized in commercial quantities and the lands are not needed for other purposes, the geothermal lessee will have a preferential right to renew the lease for fifty-five years, under terms and conditions as the BLM deems appropriate.
For BLM leases issued before August 8, 2005, the geothermal lessee is required to pay an annual rental fee (on a per acre basis), which escalates according to a schedule described therein, until production of geothermal steam in commercial quantities has commenced. After such production has commenced, the geothermal lessee is required to pay royalties (on a monthly basis) on the amount or value of (i) steam, (ii) by-products derived from production, and (iii) commercially de-mineralized water sold or utilized by the project (or reasonably susceptible to such sale or use).
For BLM leases issued after August 8, 2005, (i) a geothermal lessee who has obtained a lease through a non-competitive bidding process will pay an annual rental fee equal to $1.00 per acre for the first ten years and $5.00 per acre each year thereafter; and (ii) a geothermal lessee who has obtained a lease through a competitive process will pay a rental equal to $2.00 per acre for the first year, $3.00 per acre for the second through tenth year and $5.00 per acre each year thereafter. Rental fees paid before the first day of the year for which the rental is owed will be credited towards royalty payments for that year. For BLM leases issued, effective, or pending on August 5, 2005 or thereafter, royalty rates are fixed between 1.0-2.5% of the gross proceeds from the sale of electricity during the first ten years of production under the lease. The royalty rate set by the BLM for geothermal resources produced for the commercial generation of electricity but not sold in an arm’s length transaction is 1.75% for the first ten years of production and 3.5% thereafter. The royalty rate for geothermal resources sold by the geothermal lessee or an affiliate in an arm’s length transaction is 10.0% of the gross proceeds from the arm’s length sale. The BLM may readjust the rental or royalty rates at not less than twenty yeartwenty-year intervals beginning thirty-five years after the date geothermal steam is produced.
In the event of a default under any BLM lease, or the failure to comply with any of the provisions of the Geothermal Steam Act or regulations issued under the Geothermal Steam Act or the terms or stipulations of the lease, the BLM may, 30 days after notice of default is provided to the relevant project, (i) suspend operations until the requested action is taken, or (ii) cancel the lease.
Private Geothermal Leases
Certain of our domestic project subsidiaries have entered into geothermal resources leases with private parties, pursuant to which they have obtained the right to conduct their geothermal development and operations on privately owned land. In many cases, the lessor under these private geothermal leases owns only the geothermal resource and not the surface of the land.
Typically, the leases grant our project subsidiaries the exclusive right and privilege to drill for, produce, extract, take and remove from the leased land water, brine, steam, steam power, minerals (other than oil), salts, chemicals, gases (other than gases associated with oil), and other products produced or extracted by such project subsidiary. The project subsidiaries are also granted certain non-exclusive rights pertaining to the construction and operation of plants, structures, and facilities on the leased land. Additionally, the project subsidiaries are granted the right to dispose geothermal fluid as well as the right to re-inject into the leased land water, brine, steam, and gases in a well or wells for the purpose of maintaining or restoring pressure in the productive zones beneath the leased land or other land in the vicinity. Because the private geothermal leases do not grant to the lessee the exclusive right to use the surface of the land, the lessor reserves the right to conduct other activities on the leased land in a manner that does not unreasonably interfere with the geothermal lessee’s uses of the same land, which other activities may include agricultural use (farming or grazing), recreational use and hunting, and/or wind or solar energy developments.
The leases provide for a term consisting of a primary term in the range of five to 30 years, depending on the lease, and so long thereafter as lease products are being produced or the project subsidiary is engaged in drilling, extraction, processing, or reworking operations on the leased land.
As consideration under most of our project subsidiaries’ private leases, the project subsidiary must pay to the lessor a certain specified percentage of the value “at the well” (which is not attributable to the enhanced value of electricity generation), gross proceeds, or gross revenues of all lease products produced, saved, and sold on a monthly basis. In certain of our project subsidiaries’ private leases, royalties payable to the lessor by the project subsidiary are based on the gross revenues received by the lessee from the sale or use of the geothermal substances, either from electricity production or the value of the geothermal resource “at the well”.
In addition, pursuant to the leases, the project subsidiary typically agrees to commence drilling, extraction or processing operations on the leased land within the primary term, and to conduct such operations with reasonable diligence until lease products have been found, extracted and processed in quantities deemed “paying quantities” by the project subsidiary, or until further operations would, in such project subsidiary’s judgment, be unprofitable or impracticable. The project subsidiary has the right at any time within the primary term to terminate the lease and surrender the relevant land. If the project subsidiary has not commenced any such operations on said land (or on the unit area, if the lease has been unitized), or terminated the lease within the primary term, the project subsidiary must pay to the lessor, in order to maintain its lease position, annually in advance, a rental fee until operations are commenced on the leased land.
If the project subsidiary fails to pay any installment of royalty or rental when due and if such default continues for a period of fifteen days specified in the lease, for example, after its receipt of written notice thereof from the lessor, then at the option of the lessor, the lease will terminate as to the portion or portions thereof as to which the project subsidiary is in default. If the project subsidiary defaults in the performance of any obligations under the lease, other than a payment default, and if, for a period of 90 days after written notice is given to it by the lessor of such default, the project subsidiary fails to commence and thereafter diligently and in good faith take remedial measures to remedy such default, the lessor may terminate the lease.
We do not regard any property that we lease as material unless and until we begin construction of a power plant on the property, that is, until we drill a production well on the property.
Description of Our Power Plants
Domestic Operating Power Plants
The following descriptions summarize certain industry metrics for our domestic operating power plants:
Brady Complex
Brady Complex | |
Location | Churchill County, Nevada |
Generating Capacity | 18 MW |
Number of Power Plants | Two (Brady and Desert Peak 2 power plants). |
Technology | The Brady complex utilizes binary and flash systems. The complex uses air and water-cooled systems. |
Subsurface Improvements | 12 production wells and |
Major Equipment | Three |
Age | The Brady power plant commenced commercial operation in 1992 and a new OEC |
Land and Mineral Rights | The Brady complex is comprised mainly of BLM |
Access to Property | Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the leases, and the Brady power plant holds rights of way from the BLM and from |
Resource Information | The resource temperatures at the Brady and Desert Peak 2 power plants are 270 degrees Fahrenheit and 338 degrees Fahrenheit, respectively. |
The Brady and Desert Peak geothermal systems are located within the Hot Springs Mountains, approximately 60 miles northeast of Reno, Nevada, in northwestern Churchill County. | |
The dominant geological feature of the Brady area is a linear | |
The Desert Peak geothermal field is located within the Hot Springs Mountains, which form part of the western boundary of the Carson Sink. The structure is characterized by east-titled fault blocks and
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The geologic structure in the area is dominated by high-angle normal faults of varying displacement. |
Resource Cooling | During the last |
Sources of Makeup Water | Condensed steam is used for makeup water. |
Power Purchaser | The Sierra Pacific Power Company and Nevada Power Company purchase power generated by the Brady power plant |
PPA Expiration Date | Brady power plant — 2022. Desert Peak 2 power plant — 2027. |
Financing | |
Supplemental Information | We are currently in the |
Brawley Complex
Location | Imperial County, California |
Generating Capacity | 13 MW (See supplemental information below) |
Number of Power Plants | One |
Technology | The Brawley power plant utilizes a water-cooled binary system. |
Subsurface Improvements | 36 wells have been drilled and are connected to the Brawley power plant through its gathering system. As we improved our knowledge of the |
Major Equipment | Five OECs together with the Balance of Plant equipment. |
Age | The Brawley power plant commenced commercial operation on March 31, 2011. |
Land and Mineral Rights | The Brawley area is comprised entirely of private leases. The leases are held by production. The scheduled expiration date for all of these leases is after the end of the expected useful life of the power plant. |
The plant’s rights to use the geothermal and surface rights under the leases are subject to various conditions, as described above in “Description of Our Leases and Lands”. | |
Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the leases. | |
Resource Information | Brawley production is from deltaic and marine sedimentary sands and sandstones deposited in the subsiding Salton Trough of the Imperial Valley. Based on seismic refraction surveys the total thickness of these sediments in the Brawley area is over 15,000 feet. The shallow production reservoir (from depths of 1,500 to 4,500 feet) that was developed is fed by fractures and matrix permeability and is conductively heated from the underlying fractured reservoir which convectively circulates magmatically heated fluid. Produced fluid salinity ranges from 20,000 to 50,000 ppm, and the moderate scaling and corrosion potential is chemically inhibited. The temperature of the deeper fractured reservoir fluids exceed 525 degrees Fahrenheit, but the fluid is not yet developed because of severe scaling and corrosion potential. The deep reservoir is not dedicated to the Brawley power plant. |
The average produced fluid resource temperature is 310 degrees Fahrenheit. | |
Resource Cooling | The temperature of the geothermal resource depends on the mix of operating production wells that we use. |
Sources of Makeup Water | Water is provided by the IID. |
Power Purchaser | Southern California Edison |
PPA Expiration Date | 2031. |
Financing | Corporate funds and ITC cash grant from the U.S. Treasury. |
Supplemental Information | We are currently selling the power generated by the Brawley complex to Southern California Edison under an existing PPA at a capacity level of approximately 8 MW and we are planning to increase this level to 11 MW by the end of 2018 and further thereafter. With a new chemical supply system, we plan to activate several idle wells and we recently drilled a well in eastern Brawley and connected it to the power plant. As a result, we expect to see an increase in generation. |
Don A. Campbell Complex
Location | Mineral County, Nevada |
Generating Capacity | 41 MW |
Number of Power Plants | Two (phase 1 and phase 2) |
Technology | The Don A. Campbell power plants utilize an air-cooled binary system. |
Subsurface Improvements | |
Material Equipment | Two air-cooled |
Age | The phase 1 power plant |
Land and Mineral Rights | The Don A. Campbell area is comprised of BLM leases. |
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Resource Information | The Don A. Campbell geothermal reservoir consists of highly fractured, silicified alluvium over at least two square miles. Production and injection are very shallow with |
The temperature of the resource is approximately | |
Resource Cooling | Temperature started declining in mid-2016. |
Access to Property | Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted in leases from BLM. |
Power Purchaser | Two separate PPAs with SCPPA. |
PPA Expiration Date | The phase 1 PPA expires in 2034 and the |
Financing | |
Supplemental Information | In April 2015, we closed an equity transaction with Northleaf in which Northleaf acquired a 36.75% equity interest in ORPD. ORPD owns the Puna complex, the Don A. Campbell phase 1 power plant, and the OREG 1, OREG 2, and OREG 3 power plants. |
In November 2016, Northleaf purchased a 36.75% equity interest in the Don A. Campbell phase 2 power plant, which was initially added to the existing ORPD portfolio and then later contributed to Opal Geo, which is indirectly owned by ORPD, in connection with the tax equity partnership | |
Heber Complex | |
Location | Heber, Imperial County, California |
Generating Capacity | |
Number of Power Plants | Five (Heber 1, Heber 2, Heber South, Gould 1 and Gould 2). |
Technology | The Heber 1 plant |
Subsurface Improvements | 27 production wells and 38 injection wells connected to the plants through a gathering system. |
Major Equipment | 17 |
Age | The Heber 1 plant, |
Land and Mineral Rights | The |
The complex’s rights to use the geothermal and surface rights under the leases are subject to various conditions, as described above in “Description of Our Leases and Lands”. | |
Access to Property | Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the leases. |
Resource Information | The resource supplying the flash flowing Heber 1 wells averages 341 degrees Fahrenheit. The resource supplying the pumped Heber 2 wells averages 316 degrees Fahrenheit. |
The Heber complex’s production is from deltaic sedimentary sandstones deposited in the subsiding Salton Trough of California’s Imperial Valley. Produced fluids rise from near the magmatic heated basement rocks (18,000 feet) via fault/fracture zones to the near surface. Heber 1 wells produce directly from deep (4,000 to 8,000 feet) fracture zones. Heber 2 wells produce from the nearer surface (2,000 to 4,000 feet) matrix permeability sandstones in the horizontal outflow plume fed by the fractures from below and the surrounding ground waters. | |
Scale deposition in the flashing Heber 1 producers is controlled by down hole chemical inhibition supplemented with occasional mechanical cleanouts and acid treatments. There is no scale deposition in the Heber 2 production wells. |
Resource Cooling | Average cooling of one degree Fahrenheit per year was observed during the past 20 years of production. |
Sources of Makeup Water | Water is provided by condensate and by the IID. |
Power Purchaser | One PPA with Southern California Edison and two PPAs with SCPPA. |
PPA Expiration Date | Heber 1 — 2025, Heber 2 — 2023, and Heber South — 2031. The output from the Gould 1 and Gould 2 power plants is sold under the PPAs with |
Financing | The Heber complex was financed through the sale of OrCal Senior Secured Notes and the proceeds of the transaction involving our subsidiary ORTP |
Supplemental Information | We are currently in the process of enhancing the Heber 1 power plant. We are planning to convert artesian wells to pumped wells, add a new water cooling unit and replace one of the OECs, following which we expect the capacity of the complex to reach 89 MW. Construction is ongoing and completion of the enhancement is expected in the first quarter of 2018. |
Jersey Valley Power Plant | |
Location | Pershing County, Nevada |
Generating Capacity | 10 MW |
Number of Power Plants | One |
Technology | The Jersey Valley power plant utilizes an air cooled binary system. |
Subsurface Improvements | Two production wells and four injection wells are connected to the plant through a gathering system. |
Major Equipment | Two |
Age | Construction of the power plant was completed at the end of 2010 and the off-taker approved commercial operation |
Land and Mineral Rights | The Jersey Valley |
The power plant’s rights to use the geothermal and surface rights under the leases are subject to various conditions, as described above in “Description of Our Leases and Lands”. | |
Access to Property | Direct access to public roads from leased property and access across leased property are provided under surface rights granted in leases from BLM. |
Resource Information | The Jersey Valley geothermal reservoir consists of a small high-permeability area surrounded by a large low-permeability area. The high-permeability area has been defined by wells drilled along an interpreted fault trending west-northwest. Static water levels are artesian; two of the wells along the permeable zone have very high productivities, as indicated by Permeability Index (PI) values exceeding 20 gpm/psi. The average temperature of the resource is |
Resource Cooling | The rate of cooling was four degrees Fahrenheit in 2015, but |
Power Purchaser | Nevada Power Company |
PPA Expiration Date | 2032 |
Financing | The Jersey Valley power plant was financed through the sale of our OFC 2 Senior Secured Notes, corporate funds, an ITC cash grant from the U.S. Treasury and the proceeds of the Opal Geo tax equity partnership transaction. |
Mammoth Complex | |
Location | Mammoth Lakes, California |
Generating Capacity | 29 MW |
Number of Power Plants | Three (G-1, G-2, and G-3). |
Technology | The Mammoth complex utilizes air cooled binary systems. |
Subsurface Improvements | Ten production wells and five injection wells are connected to the plants through a gathering system. |
Major Equipment | Two new OECs and six turbo-expanders together with the Balance of Plant equipment. |
Age | The G-1 plant commenced commercial |
Land and Mineral Rights | The |
The complex’s rights to use the geothermal and surface rights under the leases are subject to various conditions, as described above in “Description of Our Leases and Lands”. | |
Access to Property | Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the leases. |
Resource Information | The average resource temperature is 339 degrees Fahrenheit. |
The Casa Diablo/Basalt Canyon geothermal field at Mammoth lies on the southwest edge of the resurgent dome within the Long Valley Caldera. It is believed that the present heat source for the geothermal system is an active magma body underlying the Mammoth Mountain to the northwest of the field. Geothermal waters heated by the magma flow from a deep source (greater than 3,500 feet) along faults and fracture zones from northwest to southeast east into the field area. | |
The produced fluid has | |
Resource Cooling | In the last three years the temperature has stabilized and there |
Power Purchaser | G1 and G3 plants — PG&E and G2 plant — Southern California Edison. |
PPA Expiration Date | G-1 and G-3 plants — 2034 and G-2 plant — 2027. |
Financing |
| The prior financing transactions covering the Mammoth complex have been fully paid off. |
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McGinness Hills Complex | |
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Number of Power Plants | Two (first phase and second phase) |
Technology | The McGinness Hills complex utilizes an air cooled binary system. |
Subsurface Improvements | Ten production wells and six injection wells are connected to the power plant. |
Material Equipment | Six air cooled |
Age | The first phase power plant commenced commercial operation on July 1, 2012, and the second phase power plant commenced commercial operation on February 1, 2015. |
Land and Mineral Rights | The McGinness Hills |
The leases require annual rental payments, as described above in “Description of Our Leases and Lands”. | |
The rights to use the geothermal and surface rights under the leases are subject to various conditions, as described above in | |
Resource Information | The McGinness Hills geothermal reservoir is contained within a network of fractured rocks over an area at least three square miles. The reservoir is contained in both Tertiary intrusive and Paleozoic sedimentary (basement) rocks. The thermal fluids within the reservoir are inferred to flow upward through the basement rocks along the NNE-striking faults at several fault intersections. The thermal fluids then generally outflow laterally to the NNE and SSW along the NNE-striking faults. No modern thermal manifestations exist at McGinness Hills, although hot spring deposits encompass an area of approximately 0.25 square miles and indicate a history of surface thermal fluid flow. The resource temperature averages 335 degrees Fahrenheit and the fluids are sourced from the reservoir |
Resource Cooling | The temperature has been stable with no notable cooling since the first phase power plant began |
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Access to Property | Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted |
Power Purchaser | |
PPA Expiration Date | |
Financing | |
OREG 1 Power Plant | |
Location | Four gas compressor stations along the Northern Border natural gas pipeline in North and South Dakota. |
Generating Capacity | 22 MW |
Number of Units | Four |
Technology | The OREG 1 power plant utilizes our air cooled |
Major Equipment | Four WHOH and four |
Age | The OREG 1 power plant commenced commercial |
Land | Easement from NBPL. |
Access to Property | Direct access to the plant from public roads. |
Power Purchaser | Basin Electric Power Cooperative |
PPA Expiration Date | 2031 |
Financing | Corporate funds. |
Supplemental Information | In April 2015, we closed an equity transaction with Northleaf in which Northleaf acquired a 36.75% equity interest in |
OREG 2 Power Plant | |
Location | Four gas compressor stations along the Northern Border natural gas pipeline; one in Montana, two in North Dakota, and one in Minnesota. |
Generating Capacity | 22 MW |
Number of Units | Four |
Technology | The OREG 2 power plant utilizes our air cooled |
Major Equipment | Four WHOH and four |
Age | The OREG 2 power plant commenced commercial |
Land | Easement from NBPL. |
Access to Property | Direct access to the plant from public roads. |
Power Purchaser | Basin Electric Power Cooperative |
PPA Expiration Date | 2034 |
Financing | Corporate funds. |
Supplemental Information | In April 2015, we closed an equity transaction with Northleaf in which Northleaf acquired a 36.75% equity interest in |
Don A. Campbell phase 2 power plant. | |
OREG 3 Power Plant | |
Location | A gas compressor station along Northern Border natural gas pipeline in Martin County, Minnesota. |
Generating Capacity | 5.5 MW |
Number of Units | One |
Technology | The OREG 3 power plant utilizes our air cooled |
Major Equipment | One WHOH and one OEC |
Age | The OREG 3 power plant commenced commercial |
Land | Easement from NBPL. |
Access to Property | Direct access to the plant from public roads. |
Power Purchaser | Great River Energy |
PPA Expiration Date | 2029 |
Financing | Corporate funds. |
Supplemental Information | In April 2015, we closed an equity transaction with Northleaf in which Northleaf acquired a 36.75% equity interest in |
OREG 4 Power Plant | |
Location | A gas compressor station along natural gas pipeline in Denver, Colorado. |
Generating Capacity | 3.5 MW |
Number of Units | One |
Technology | The OREG 4 power plant utilizes our air cooled |
Major Equipment | Two WHOH and one OEC |
Age | The OREG 4 power plant commenced commercial |
Land | Easement from Trailblazer Pipeline Company. |
Access to Property | Direct access to the plant from public roads. |
Power Purchaser | Highline Electric Association |
PPA Expiration Date | 2029 |
Financing | Corporate funds. |
Ormesa Complex | |
Location | East Mesa, Imperial County, California |
Generating Capacity | 40 MW |
Number of Power Plants | Three (OG I, OG II and GEM 3). The GEM 2 plant was taken off line during 2015 due to plant operation optimization. |
Technology | The OG I and OG II plants utilize a binary system and the GEM 3 plant |
Subsurface Improvements | 24 production wells and 57 injection wells connected to the plants through a gathering system. |
Material Major Equipment | 8 |
Age | The various OG I plants commenced commercial |
Land and Mineral Rights | The |
The complex’s rights to use the geothermal and surface rights under the leases are subject to various conditions, as described above in “Description of Our Leases and Lands”. | |
Access to Property | Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the leases. |
Resource Information | The |
Productive sandstones are |
Resource Cooling | In the last year, the temperature has declined by |
Sources of Makeup Water | Water is provided by the IID. |
Power Purchaser | |
PPA Expiration Date | November |
Financing | |
Supplemental Information | |
Puna Complex | |
Location | Puna district, Big Island, Hawaii |
Generating Capacity | 38 MW |
Number of Power Plants | Two |
Technology | The Puna plants utilize our geothermal combined cycle and binary systems. The plants use an air cooled system. |
Subsurface Improvements | Six production wells and five injection wells connected to the plants through a gathering system. |
Major Equipment | |
Age | The first plant commenced commercial |
Land and Mineral Rights | The Puna complex is comprised of a private lease. The private lease is between PGV and KLP and it expires in 2046. PGV pays an annual rental payment to KLP, which is adjusted every five years based on the CPI. |
The state of Hawaii owns all mineral rights (including geothermal resources) in the state. The state has issued a Geothermal Resources Mining Lease to KLP, and KLP in turn has entered into a sublease agreement with PGV, with the state’s consent. Under this arrangement, the state receives royalties of approximately three percent of the gross revenues. | |
Access to Property | Direct access to the leased property is readily available via county public roads located adjacent to the leased property. The public roads are at the north and south boundaries of the leased property. |
Resource Information | The geothermal reservoir at Puna is located in volcanic rock along the axis of the Kilauea Lower East Rift Zone. Permeability and productivity are controlled by rift-parallel subsurface fissures created by volcanic activity. They may also be influenced by lens-shaped bodies of pillow basalt which have been postulated to exist along the axis of the rift at depths below 7,000 feet. |
The distribution of reservoir temperatures is strongly influenced by the configuration of subsurface fissures and temperatures are among the hottest of any geothermal field in the world, with maximum measured temperatures consistently above 650 degrees Fahrenheit. |
Resource Cooling | The resource temperature is stable. |
Power Purchaser | Three PPAs with HELCO (see “Supplemental Information” below). |
PPA Expiration Date | 2027 |
Financing | |
Supplemental Information |
• | For the first on-peak 25 MW, based on HELCO's avoided cost. | |
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• | For the new on-peak 8 MW, | |
• | For the first off-peak 22 MW | |
The off-peak energy above 22 MW is dispatchable: | ||
1. | For the first off-peak 5 MW, | |
2. | For the energy above 27 MW | |
The capacity payment for the first 30 MW | ||
Steamboat Complex | |
Location | Steamboat, Washoe County, Nevada |
Generating Capacity | |
Number of Power Plants | Six (Steamboat 2 and 3, Burdette (Galena 1), Steamboat Hills, Galena 2 and Galena 3). |
Technology | The Steamboat complex utilizes a binary system (except for Steamboat Hills, which utilizes a single flash system). The complex uses air and water cooling systems. |
Subsurface Improvements |
Major Equipment | Nine individual air-cooled OECs and one water-cooled OEC, |
Age | The power plants commenced commercial operation in 1992, 2005, 2007 and 2008. During 2008, the Rotoflow expanders at Steamboat 2 and 3 were replaced with four turbines manufactured by us. |
Land and Mineral Rights | The total Steamboat area is comprised of 41% private leases, 41% BLM leases and 18% private land owned by us. The leases are held by production. The scheduled expiration dates for all of these leases are after the end of the expected useful life of the power plants. |
The complex’s rights to use the geothermal and surface rights under the leases are subject to various conditions, as described above in “Description of Our Leases and Lands”. | |
We have easements for the transmission lines we use to deliver power to our power purchasers. | |
Resource Information | The resource temperature at the lower area averages |
The Steamboat geothermal field is a typical basin and range geothermal reservoir. Large and deep faults that occur in the rocks allow circulation of ground water to depths exceeding 10,000 feet below the surface. Horizontal zones of permeability permit the hot water to flow eastward in an out-flow plume. | |
The Steamboat Hills and Galena 2 power plants produce hot water from fractures associated with normal faults. The rest of the power plants acquire their geothermal water from the horizontal out-flow plume. | |
The water in the Steamboat reservoir has a low total solids concentration. Scaling potential is very low unless the fluid is allowed to flash which will result in calcium carbonate scale. Injection of cooled water for reservoir pressure maintenance prevents flashing. | |
Resource Cooling | |
Access to Property | Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the leases. |
Sources of Makeup Water | Water is provided by condensate and the local utility. |
Power Purchaser | Sierra Pacific Power Company (for Steamboat 2 and 3, Burdette (Galena1), Steamboat Hills, and Galena 3) and Nevada Power Company (for Galena 2). |
PPA Expiration Date | Steamboat 2 and 3 — 2022, Burdette (Galena1) — 2026, Steamboat Hills — 2018, Galena 3 — 2028, and Galena 2 — 2027. |
Financing | |
Supplemental information | In |
Tungsten Mountain (U.S.) | |
Location | Churchill County, Nevada |
Generating Capacity | 26 MW |
Number of Power Plants | One |
Technology | The Tungsten Mountain power plant utilizes an air cooled binary system. |
Subsurface Improvements | Four production and three injection |
Major Equipment | One air cooled OEC with the Balance of Plant equipment. |
Age | The power plant commenced commercial operation on December 1, 2017. |
Land and Mineral Rights | The Tungsten Mountain area is comprised of BLM land. |
Resource Information | The project exploits blind resource (no hot springs or fumaroles) in an |
Resource Cooling | The resource temperature is stable. |
Access to Property | Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted in leases from BLM. |
Power Purchaser | SCPPA PPA until 2043. |
Financing | Corporate funds during construction. |
Tuscarora Power Plant | |
Location | Elko County, Nevada |
18 MW | |
Number of Power Plants | One |
Technology | The Tuscarora power plant utilizes a water cooled binary system. |
Subsurface Improvements | |
Major Equipment | Two water cooled |
Age | The power plant commenced commercial operation on January 11, 2012. |
Land and Mineral Rights | The Tuscarora area is comprised of private and BLM leases. |
The leases are currently held by payment of annual rental payments, as described above in “Description of Our Leases and Lands”. | |
The plant’s rights to use the geothermal and surface rights under the leases are subject to various conditions, as described above in “Description of Our Leases and Lands”. | |
Resource Information | The Tuscarora geothermal reservoir consists of an area of approximately 2.5 square miles. The reservoir is contained in both Tertiary and Paleozoic (basement) rocks. The Paleozoic section consists primarily of sedimentary rocks, overlain by tertiary volcanic rocks. Thermal fluid in the native state of the reservoir flows upward and to the north through apparently southward-dipping, basement formations. At an elevation of roughly 2,500 feet with respect to mean sea level, the upwelling thermal fluid enters the tertiary volcanic rocks and flows directly upward, exiting to the surface at Hot Sulphur Springs. |
The average resource temperature is | |
Resource Cooling | |
Access to Property | Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted in leases from BLM. |
Sources of Makeup Water | Water is provided from five water makeup wells. |
Power Purchaser | Nevada Power Company |
PPA Expiration Date | 2032 |
Financing | OFC 2 Senior Secured Notes, ITC cash grant from the U.S. Treasury and the OrLeaf transaction. |
Supplemental information | Due to the |
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Amatitlan Power Plant (Guatemala) | |
Location | Amatitlan, Guatemala |
Generating Capacity | 20 MW |
Number of Power Plants | One |
Technology | The Amatitlan power plant utilizes an air cooled binary system and a small back pressure steam turbine (one MW). |
Subsurface Improvements | Six production wells and two injection wells connected to the plants through a gathering system. |
Major Equipment | Two OECs and one |
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Age | The plant commenced commercial operation in 2007. |
Land and Mineral Rights | Total resource concession area (under usufruct agreement with INDE) is for a term of 25 years starting in April 2003. Leased and company owned property is approximately 3% of the concession area. Under the agreement with INDE, the power plant company pays royalties of 3.5% of revenues up to 20.5 MW generated and 2% of revenues exceeding 20.5 MW generated. |
The generated electricity is sold at the plant fence. The transmission line is owned by INDE. | |
Resource Information | The resource temperature is an average of 518 degrees Fahrenheit. |
The Amatitlan geothermal area is located on the north side of the Pacaya Volcano at approximately 5,900 feet above sea level. | |
Hot fluid circulates up from a heat source beneath the volcano, through deep faults to shallower depths, and then cools as it flows horizontally to the north and northwest to hot springs on the southern shore of Lake Amatitlan and the Michatoya River Valley. |
Resource Cooling | Approximately two degrees Fahrenheit per year. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Access to Property | Direct access to public roads from the leased property and access across the leased property are provided under surface rights granted pursuant to the lease agreement. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Power Purchasers | INDE and another local purchaser. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PPA Expiration Date | The PPA with INDE expires in 2028. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Financing | Senior secured limited recourse project finance loan from Banco Industrial S.A. and Westrust Bank (International) Limited. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Bouillante power plant (Guadeloupe) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Location | Guadeloupe, a French territory in the Caribbean | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Generating Capacity | 15 MW | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Number of Power Plants | One | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Technology | The Bouillante power plant uses direct steam turbines. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Subsurface Improvements | Two production wells and one injection well connected to the plant through a gathering system. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Major Equipment | Two steam turbines together with the Balance of Plant equipment. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Age | The first turbine commenced commercial operation in 1995 and the second turbine commenced operation in 2004. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Land and Mineral Rights | Geothermal concession of roughly 24 square miles valid through April 30, 2050. Facilities located on land held in fee, as well as long-term leases and easements. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Resource Information | The resource temperature is an average of 485 degrees Fahrenheit. Production comes from a fault that extends from the mountain into the ocean. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Resource Cooling | The resource temperature is stable. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Access to Property | Direct access to site through public roads. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Power Purchaser | EDF pursuant to a PPA. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PPA Expiration Date | December 31, 2030. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Financing | Corporate funds | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Supplemental information | 80% of the project is owned jointly by Ormat and CDC allocated 75% to Ormat and 25% to CDC. Ormat and CDC will gradually increase their combined interest in the project to 85% and Sageos will hold the remaining balance. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
We plan to convert two idle wells to injection wells to improve reservoir pressure support. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Olkaria III Complex (Kenya)
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Projects under Construction We have several projects in various stages of construction, including three projects that we have fully released for construction and three projects that are in initial stages of construction. The following is a description of projects in the U.S., Kenya and Indonesia that were released for, and are in different stages of, construction. These projects are expected to have a total generating capacity of 72 MW (representing our interest). In addition, we are planning to add 4 MW to the Brady complex, as described above. The McGinness Hills geothermal reservoir is contained within a network of fractured rocks over an area of at least three square miles. The reservoir is contained in both Tertiary intrusive and Paleozoic sedimentary (basement) rocks. The thermal fluids within the reservoir are inferred to flow upward through the basement rocks along the NNE-striking faults at several fault intersections. The thermal fluids then generally outflow laterally to the NNE and SSW along the NNE-striking faults. No modern thermal manifestations exist at McGinness Hills, although hot spring deposits encompass an area of approximately 0.25 square miles and indicate a history of surface thermal fluid flow. The resource temperature averages 335 degrees Fahrenheit and the fluids are sourced from the reservoir at elevations between 2,000 to 5,000 feet below the surface. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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PlatanaresSarulla
NIL 2 (Indonesia)
Location | Tapanuli Utara North Sumatra Namura I Langit area, Indonesia. |
Ownership | SOL is a consortium consisting of Medco Energi Internasional Tbk, Inpex Corporation, Itochu Corporation, Kyushu Electric Power Co. Inc., |
Projected Generating Capacity | One phase, NIL 2, has a total projected generating capacity of approximately 110 MW (Ormat’s share is approximately 14 MW). |
Projected Technology | Integrated Geothermal Combined Cycle Unit comprised of one back pressure steam turbine and six OECs. |
Condition | The first two phases (SIL and NIL 1, with a combined generating capacity of 220 MW) commenced commercial operation in March and October 2017, respectively. For the third phase, NIL 2, engineering, procurement and construction work at the site are in progress and all of Ormat’s equipment has been delivered and installed. Drilling for the third phase is still ongoing and the project has achieved to date, based on preliminary estimates, 100% of the required production and injection capacity. |
Land and Mineral Rights | Most of the aboveground land for the project was acquired from private owners with some land leased from governmental agencies. Mineral rights are state owned with special agreement for its usage by the project. |
Resource Information | Two field areas, NIL and SIL host a steam-liquid-dominated system. Previously drilled wells have temperatures from 275°C to 310°C. Currently most wells are flowing at an average rate of about 750T/Hr per well which is sufficient for over 20 MW electrical production. |
Access to Property | Access to property for the project has been secured. |
Power Purchaser | 30-year Energy Sales Contract with PLN (the state electric utility) |
Financing | In May 2014, SOL reached financial closing on $1.17 billion to finance the development of the project with a consortium of lenders comprised of JBIC, the Asian Development Bank and six other commercial banks. Under this financing, the project company obtained construction and term loans under a limited recourse financing package backed by political risk guarantee from JBIC. |
Projected Operation | NIL 2 will be commissioned in two stages. Approximately 80 MW will be commissioned in the first quarter of 2018 and approximately 30 MW will be commissioned by mid-April 2018. |
Supplemental Information | The Sarulla project is owned and operated by the consortium members under the framework of a JOC and ESC. Under the JOC, PT Pertamina Geothermal Energy, the concession holder for the project, has provided the consortium with the right to use the geothermal field, and under the ESC, PLN, the state electric utility, is the off-taker at Sarulla for a period of 30 years. |
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In addition to our equity holdings in the consortium, we designed the Sarulla power plant and supplied our OECs to the power plant. | |
The |
The following is a description of projects in California and Nevada with an expected total generating capacity of 42 MW that are in an initial stage of construction:
Carson Lake Project (U.S.) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Location | Churchill County, Nevada | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Projected Generating Capacity | 10 MW | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Projected Technology | The Carson Lake power plant will utilize a binary system. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Condition | Initial stage of
Future Projects
Projects under Various Stages of Development
We also have projects under various stages of development in the U.S., Guadeloupe and Kenya. We expect to continue to explore these and other opportunities for expansion so long as they continue to meet our business objectives and investment criteria.
The following is a description of the projects currently under various stages of development and for which we are able to estimate their expected generating capacity. Upon completion of these projects, the generating capacity of
Bouillante power plant We are planning to increase the capacity of theBouillanteproject by an additional
Menengai Project (Kenya)
On November 3, 2014, our majority owned Kenyan subsidiary
Under the PISSA,
Puna Enhancement Project (Hawaii) We are planning to replace 10 old steam units with two new OECs and to upgrade the existing auxiliary equipment. This upgrade will increase the Puna complex generating capacity by 8 MW to 46 MW. We have entered into negotiations with HELCO to secure a PPA for increased generation during the original term of the existing PPAs and to extend the period beyond 2027. We expect the upgrade to be completed by late 2019 or early 2020. Dixie Meadows We are currently developing the 15 MW to 20 MW Dixie Meadows geothermal power plant in Churchill County, Nevada. Following evaluation of drilling results, we have concluded that injection wells should be located in an area which is currently designated as protected land. We are exploring ways to remove the federal designation. Until we complete this process, we have put this project on hold. Steamboat Solar We are planning to develop a 5 MW Solar PV project on the site of the Steamboat geothermal complex. We plan to install Solar PV systems to reduce internal consumption loads. Future Prospects
We have a substantial land position that is expected to support future developmentand on which we have started or plan to start exploration activity. When deciding whether to continue holding lease rights and/or to pursue exploration activity, we diligently prioritize our prospective investments, taking into account resource and probability assessments in order to make informed decisions about whether a particular project will support commercial As a result, during fiscal year
Our current land position is comprised of various leases, concessions and private land for geothermal resources of approximately
Nevada
California (3)
Oregon
New Mexico (1)
Utah (2)
Guatemala (2)
Guadeloupe (1)
New Zealand (1)
Honduras (1)
Ethiopia (4)
Storage Projects
In addition to our Geothermal activity, we are currently working to develop energy storage projects in the U.S. including the following:
ACUA We are developing a 1 MW/1 MWh behind the meter energy storage system that will be installed in the Atlantic County Utility Authority’s (ACUA) wastewater treatment plant in Atlantic City, New Jersey. We will own and operate the battery energy storage systems to create energy savings for ACUA, including by participating in PJM’s frequency regulation market. Commercial operation is expected in March 2018. Stryker and Plumstead We are developing two 20 MW/20 MWh IFM energy storage systems. The Stryker project is located near Allentown, NJ and the Plumsted project is located near Trenton, NJ. We are acting as EPC lead and owner and operator of both projects. The energy storage systems will participate in PJM’s frequency regulation market.
Operations of our Product Segment
Power Units for Geothermal Power Plants. We design, manufacture, and sell power units for geothermal electricity generation, which we refer to as OECs. Our customers include contractors and geothermal plant owners and operators.
The power units are usually paid for in installments, in accordance with milestones set forth in the supply agreement. Sometimes we agree to provide the purchaser with spare parts (or alternatively, with a non-exclusive license to manufacture such parts). We provide the purchaser with at least a 12-month warranty for such products. We usually also provide the purchaser (often upon receipt of advances made by the purchaser) with a guarantee, which
Power Units for Recovered Energy-Based Power Generation. We design, manufacture, and sell power units used to generate electricity from recovered energy or so-called “waste heat”. Our existing and target customers include interstate natural gas pipeline owners and operators, gas processing plant owners and operators, cement plant owners and operators, and other companies engaged in other energy-intensive industrial processes. We have two different business models for this product line.
Remote Power Units and other Generators. We design, manufacture and sell fossil fuel powered turbo-generators with capacities ranging from 200 watts to 5,000 watts, which operate unattended in extreme hot or cold climate conditions. The remote power units supply energy
EPC of Power Plants. We engineer, procure and construct, as an EPC contractor, geothermal and recovered energy power plants on a turnkey basis, using power units we design and manufacture. Our customers are geothermal power plant owners as well as our target customers for the sale of our recovered-energy based power units described above. Unlike many other companies that provide EPC services, we believe we have an advantage in that we are using our own manufactured equipment and thus have better quality and
In connection with the sale of our power units for geothermal power plants, power units for recovered energy-based power generation, remote power units and other generators, we enter into sales agreements, from time to time,
Our manufacturing operations and products are certified ISO 9001, ISO 14001, American Society of Mechanical Engineers, and TÜV, and we are an approved supplier to many electric utilities around the world.
Backlog
We have a product backlog of approximately $
The following is a breakdown of the Product segment backlog as of March 1
Competition
In our Electricity segment, we face competition from geothermal power plant owners and developers as well as other renewable energy providers.
In our Product segment, we face competition from power plant equipment manufacturers
As we implement our new strategic plan, we will face competition from a number of sources, many of which may have resources, industry experience, market acceptance or other advantages we do not have. For example, expanding into new technologies, such as energy storage, or new markets, such as C&I, will involve competition
Electricity Segment
Competition in the Electricity segment is particularly marked in the very early stage of either obtaining the rights to the resource for
In obtaining new PPAs, we also face competition from companies engaged in the power generation business from other renewable energy sources, such as wind power, biomass, solar power and hydro-electric power. In the last few years, competition from the wind and solar power generation industries has increased significantly.
As a geothermal company, we are focused on niche markets where our
In the demand response
The energy storage and energy management space is comprised of many
Product Segment
Our competitors among power plant equipment suppliers are divided into high enthalpy and low enthalpy competitors. Our main high enthalpy competitors are industrial steam turbine manufacturers such as Mitsubishi Hitachi Power Systems, Fuji Electric Co., Ltd. and Toshiba Corporation of Japan, GE/Nuovo Pignone brand and Ansaldo Energia of Italy. As noted above, in 2015, we
Our low enthalpy competitors are binary systems manufacturers using the Organic Rankine Cycle such as Fuji Electric Co., Ltd of Japan,
In the REG business, our competitors are other Organic Rankine Cycle manufacturers (such as GE and Mitsubishi/Turboden),
Currently, none of our competitors compete with us in both the Electricity and the Product segments.
In the case of proposed EPC projects, we also compete with other service suppliers, such as project/engineering companies.
Customers
All of our revenues from the sale of electricity in the year ended December 31,
Based on publicly available information, as of December 31,
The credit ratings of any power purchaser may change from time to time. There is no publicly available information with respect to the credit rating or stability of the power purchasers under the PPAs for our foreign power plants.
Our revenues from the Product segment are derived from contractors or owners or operators of power plants, process companies, and pipelines.
Raw Materials, Suppliers and Subcontractors
In connection with our manufacturing activities, we use raw materials such as steel and aluminum. We do not rely on any one supplier for the raw materials used in our manufacturing activities, as all of these raw materials are readily available from various suppliers.
We use subcontractors for some of the manufacturing
Employees
As of December 31,
As of
In the U.S., we currently do not have employees represented by unions recognized by the Company under collective bargaining agreements. However, a union filed a petition with the NLRB seeking to organize the operations and maintenance employees at the Puna
We have no collective bargaining agreements with respect to our Israeli employees. However, by order of the Israeli Ministry of Economy and Industry, the provisions of a collective bargaining agreement between the Histadrut (the General Federation of Labor in Israel) and the Coordination Bureau of Economic Organizations (which includes the Industrialists Association) may apply to some of our Israeli non-managerial, finance and administrative, and sales and marketing personnel. This collective bargaining agreement principally concerns cost of living pay increases, length of the workday, minimum wages and insurance for work-related accidents, annual and other vacation, sick pay, and determination of severance pay, pension contributions, and other conditions of employment. We currently provide such employees with benefits and working conditions, which are at least as favorable as the conditions specified in the collective bargaining agreement.
Insurance
We maintain business interruption insurance, casualty insurance, including flood, volcanic eruption, earthquake and cyber coverage, and primary and excess liability insurance, control of wells, construction all risk, as well as customary
We generally purchase insurance policies to cover our exposure to certain political risks involved in operating in developing countries.
Regulation of the Electric Utility Industry in the United States
The following is a summary overview of the electric utility industry and applicable federal and state regulations and should not be considered a full statement of the law or all issues pertaining thereto.
PURPA
PURPA provides the owners of power plants certain benefits described below if a power plant is a “Qualifying Facility”. A small power production facility is a Qualifying Facility if: (i) the facility does not exceed 80 MW; (ii) the primary energy source of the facility is biomass, waste, renewable resources, or any combination thereof, and at least 75% of the total energy input of the facility is from these sources, and fossil fuel input is limited to specified uses; and (iii) the facility, if larger than one megawatt, has filed with FERC a notice of self-certification of qualifying status, or has filed with FERC an application for FERC certification of qualifying status that has been granted. The 80 MW size limitation, however, does not apply to a facility if (i) it produces electric energy solely by the use, as a primary energy input, of solar, wind, waste or geothermal resources; and (ii) an application for certification or a notice of self-certification of qualifying status of the facility was submitted to FERC prior to December 21, 1994, and construction of the facility commenced prior to December 31,
FERC's regulations under PURPA exempt owners of small power production Qualifying Facilities that use geothermal resources as their primary source and other Qualifying Facilities that are 30 MW or under in size from regulation under the PUHCA 2005, from many provisions of the FPA and from state laws relating to the financial, organization and rate regulation of electric utilities.
With respect to the FPA, FERC's regulations under PURPA do not exempt from the rate provisions of the FPA sales of energy or capacity from Qualifying Facilities larger than 20 MW in size that are made (a) pursuant to a contract executed after March 17, 2006 that is not a contract made pursuant to a state regulatory
In addition, PURPA and FERC’s regulations under PURPA require that electric utilities offer to purchase electricity generated by Qualifying Facilities at a rate based on the purchasing utility’s incremental cost of purchasing or producing energy (also known as “avoided cost”). However, FERC's regulations under PURPA also allow FERC, upon request of a utility, to terminate a utility’s obligation to purchase energy from Qualifying Facilities upon a finding that Qualifying Facilities have nondiscriminatory access to either: (i) independently administered, auction-based day ahead, and real time markets for energy and wholesale markets for long-term sales of capacity; (ii) transmission and interconnection services provided by a FERC-approved regional transmission entity and administered under an open-access transmission tariff that affords nondiscriminatory treatment to all customers, and competitive wholesale markets that provide a meaningful opportunity to sell capacity and energy, including long and short term sales; or (iii) wholesale markets for the sale of capacity and energy that are at a minimum of comparable competitive quality as markets described in (i) and (ii) above. FERC regulations protect a Qualifying Facility’s rights under any contract or obligation involving purchases or sales that are entered into before FERC has determined that the contracting utility is entitled to relief from the mandatory purchase obligation. FERC has granted the request of California investor-owned utilities for a waiver of the mandatory purchase obligation for Qualifying Facilities larger than 20 MW in size and is currently re-evaluating the 20 MW threshold for such waiver as well as other aspects of its PURPA regulations.
We expect that our power plants in the U.S will continue to meet all of the criteria required for Qualifying Facilities under PURPA. However, since the Heber power plants have PPAs with Southern California Edison that require Qualifying Facility status to be maintained, maintaining Qualifying Facility status remains a key obligation. If any of the Heber power plants loses its Qualifying Facility status our operations could be adversely affected. Loss of Qualifying Facility status would eliminate the Heber power plants’ exemption from the FPA and thus, among other things, the rates charged by the Heber power plants in the PPAs with Southern California Edison and SCPPA would become subject to FERC regulation. Further, it is possible that the utilities that purchase power from the power plants could successfully obtain a waiver of the mandatory-purchase obligation in their service territories. For example, the three California investor-owned utilities have received such a waiver from FERC for projects larger than 20 MW. If this occurs or if FERC reduces the 20 MW threshold or eliminates the mandatory purchase obligation, the power plants’ existing PPAs will not be affected, but the utilities will not be obligated under PURPA to renew or extend these PPAs or execute new PPAs upon the existing PPAs’ expiration, if the size is above the waiver threshold.
PUHCA
Under PUHCA 2005, the books and records of a utility holding company, its affiliates, associate companies, and subsidiaries are subject to FERC and state commission review with respect to transactions that are subject to the jurisdiction of either FERC or the state commission or costs incurred by a jurisdictional utility in the same holding company system. However, if a company is a utility holding company solely with respect to Qualifying Facilities, exempt wholesale generators, or foreign utility companies, it will not be subject to review of books and records by FERC under PUHCA 2005. Qualifying Facilities or exempt wholesale generators that make only wholesale sales of electricity are not subject to state commissions’ rate regulations and, therefore, in all likelihood would not be subject to any review of their books and records by state commissions pursuant to PUHCA 2005 as long as the Qualifying Facility is not part of a holding company system that includes a utility subject to regulation in that state.
FPA
Pursuant to the FPA,
If a power plant in the U.S. were to become subject to FERC’s ratemaking jurisdiction under the FPA as a result of loss of Qualifying Facility status and the PPA remains in effect, FERC may determine that the rates currently set forth in the PPA are not just and reasonable and may set rates that are lower than the rates currently charged. In addition, FERC may require that the power plant refund a portion of amounts previously paid by the relevant power purchaser to such power plant. Such events would likely result in a decrease in our future revenues or in an obligation to disgorge revenues previously earned by from the power plant, either of which would have an adverse effect on our revenues.
Moreover, the loss of the Qualifying Facility status of any of our power plants selling energy to Southern California Edison could also permit Southern California Edison, pursuant to the terms of its PPA, to cease taking and paying for electricity from the relevant power plant and to seek refunds for past amounts paid and/or a reduction in future payments. In addition, the loss of any such status would result in the occurrence of an event of default under the indenture for the OFC Senior Secured Notes and the OrCal Senior Secured Notes and hence would give the indenture trustee the right to exercise remedies pursuant to the indenture and the other financing documents.
State Regulation
Our power plants in California and Nevada, by virtue of being Qualifying Facilities that make only wholesale sales of electricity, are not subject to rate, financial and organizational regulations applicable to electric utilities in those states. The power plants each sell or will sell their electrical output under PPAs to electric utilities (Sierra Pacific Power Company, Nevada Power Company, Southern California Edison or SCPPA). All of the utilities except SCPPA are regulated by their respective state public utilities commissions. Sierra Pacific Power Company and Nevada Power Company, which merged and are doing business as NV Energy, are regulated by the PUCN. Southern California Edison is regulated by the
Under Hawaii law, non-fossil generators are not subject to regulation as public utilities. Hawaii law provides that a geothermal power producer is to negotiate the rate for its output with the public utility purchaser. If such rate cannot be determined by mutual accord, the PUCH will set a just and reasonable rate. If a non-fossil generator in Hawaii is a Qualifying Facility, federal law applies to such Qualifying Facility and the utility is required to purchase the energy and capacity at its avoided cost. The rates for our power plant in Hawaii are established under a long-term PPA with HELCO.
Environmental Permits
U.S. environmental permitting regimes with respect to geothermal projects center upon several general areas of focus. The first involves land use approvals. These may take the form of Special Use Permits or Conditional Use Permits from local planning authorities or a series of development and utilization plan approvals and right of way approvals where the geothermal facility is entirely or partly on BLM or U.S. Forest Service lands. Certain federal approvals require a review of environmental impacts in conformance with the federal National Environmental Policy Act. In California, some local permit approvals require a similar review of environmental impacts under a state statute known as the California Environmental Quality Act. These federal and local land use approvals typically impose conditions and restrictions on the construction, scope and operation of geothermal projects.
The second category of permitting focuses on the installation and use of the geothermal wells themselves. Geothermal projects typically have three types of wells: (i) exploration wells designed to define and verify the geothermal resource, (ii) production wells to extract the hot geothermal liquids (also known as brine) for the power plant, and (iii) injection wells to inject the brine back into the subsurface resource. For example, in Nevada and on BLM lands, the well permits take the form of geothermal drilling permits for well installation. Approvals are also required to modify wells, including for use as production or injection wells. For all wells drilled in Nevada, a geothermal drilling permit must be obtained from the Nevada Division of Minerals. Those wells in Nevada to be used for injection will also require Underground Injection Control permits from the Nevada Division of Environmental Protection. Geothermal wells on private lands in California require drilling permits from the California Department of Conservation’s DOGGR. The eventual designation of these installed wells as individual production or injection wells and the ultimate closure of any wells is also reviewed and approved by DOGGR pursuant to a DOGGR-approved Geothermal Injection Program.
A third category of permits involves the regulation of potential air emissions associated with the construction and operation of wells and power plants and surface water discharges associated with construction and operations activities. Generally, each well and plant requires a preconstruction air permit and storm water discharge permit before earthwork can commence. In addition, in some jurisdictions the wells that are to be used for production require and those used for injection may require air emissions permits to operate. Internal combustion engines and other air pollutant emissions sources at the projects may also require air emissions permits. For our projects, these permits are typically issued at the state or county level. Permits are also required to manage storm water during project construction and to manage drilling muds from well construction, as well as to manage certain discharges to surface impoundments, if any.
A fourth category of permits, that are required in both California and Nevada, includes ministerial permits such as building permits, hazardous materials storage and management permits, and pressure vessel operating permits. We are also required to obtain water rights permits in
In some cases our projects may also require permits, issued by the applicable federal agencies or authorized state agencies, regarding threatened or endangered species, permits to impact wetlands or other waters and notices of construction of structures which may have an impact on airspace. Environmental laws and regulations may change in the future, which may
As of the date of this report, all of the material environmental permits and approvals currently required for our operating power plants have been obtained. We
Environmental Laws and Regulations
Our facilities and operations are subject to a number of environmental laws and regulations relating to development, construction and operation. In the U.S, these may include the Clean Air Act, the Clean Water Act, the Emergency Planning and Community Right-to-Know Act, the Endangered Species Act, the National Environmental Policy Act, the Resource Conservation and Recovery Act, and related state laws and regulations.
Our geothermal operations involve significant quantities of brine (substantially, all of which we reinject into the subsurface) and scale, both of which can contain materials (such as arsenic, antimony, lead, and naturally occurring radioactive materials) in concentrations that exceed regulatory limits used to define hazardous waste. We also use various substances, including isopentane and industrial lubricants that could become potential contaminants and are generally flammable. Hazardous materials are also used in our equipment manufacturing operations in Israel. As a result, our projects are subject to domestic and foreign federal, state and local statutory and regulatory requirements regarding the use, storage, fugitive emissions, and disposal of hazardous substances. The cost of investigation and removal or remediation activities associated with a spill or release of such materials could be significant.
Although we are not aware of any mismanagement of these materials, including any mismanagement prior to the acquisition of some of our power plants that has materially impaired any of the power plant sites, any disposal or release of these materials onto the power plant sites, other than by means of permitted injection wells, could lead to contamination of the environment and result in material cleanup requirements or other responsive obligations under applicable environmental laws. We believe that at one time there may have been a gas station located on the Mammoth complex site, but because of significant surface disturbance and construction since that time further physical evaluation of the environmental condition of the former gas station site has been impractical. We believe that, given the subsequent surface disturbance and construction activity in the vicinity of the suspected location of the service station, it is likely that environmental contamination, if any, associated with the former facilities and any associated underground storage tanks would have already been encountered if they still existed.
Regulation Related to New Activity
Our recent entry into the energy storage space and planned provision of energy management, demand response and load shedding services require us to obtain and maintain certain additional authorizations and approvals. These include (1) authorization from FERC to make wholesale sales of power, capacity, and ancillary services at market-based rates, and (2) membership status with eligibility to serve designated contractual functions in the RTOs of PJM,
Regulation of the Electric Utility Industry in our Foreign Countries of Operation
The following is a summary overview of certain aspects of the electric industry in the foreign countries in which we have an operating geothermal power plant. As such, it should not be considered a full statement of the laws in such countries or all of the issues pertaining thereto.
Guatemala. The General Electricity Law of 1996, Decree 93-96, created a wholesale electricity market in Guatemala and established a new regulatory framework for the electricity sector. The law created a new regulatory commission, the CNEE, and a new wholesale power market administrator, the AMM, for the regulation and administration of the sector. The AMM is a private not-for-profit entity. The CNEE functions as an independent agency under the Ministry of Energy and Mines and is in charge of regulating, supervising, and controlling compliance with the electricity law, overseeing the market and setting rates for transmission services, and distribution to medium and small customers. All distribution companies must supply electricity to such customers pursuant to long-term contracts with electricity generators. Large customers can contract directly with the distribution companies, electricity generators or power marketers, or buy energy in the spot market. Guatemala has approved a Law of Incentives for the Development of Renewable Energy Power plants, Decree 52-2003, in order to promote the development of renewable energy power plants in Guatemala. This law provides certain benefits to companies utilizing renewable energy, including a 10-year exemption from corporate income tax and VAT on imports and customs duties. On September 16, 2008, CNEE issued a resolution which approved the Technical Norms for the Connection, Operation, Control and Commercialization of the Renewable Distributed Generation and Self-producers Users with Exceeding Amounts of Energy. This Technical Norm was created to regulate all aspects of generation, connection, operation, control and commercialization of electric energy produced with renewable sources to promote and facilitate the installation of new generation plants, and to promote the connection of existing generation plants which have exceeding amounts of electric energy for commercialization. It is applicable to projects with a capacity of up to 5 MW. At present, the General Electricity Law and the Law of Incentives for the Development or Renewable Energy Power Plants are still in force.
Kenya. The electric power sector in Kenya is regulated by the Kenyan Energy Act. Among other things, the Kenyan Energy Act provides for the licensing of electricity power producers and public electricity suppliers or distributors. KPLC is the only licensed public electricity supplier and has a virtual monopoly in the distribution of electricity in the country. The Kenyan Energy Act permits IPPs to install power generators and sell electricity to KPLC, which is owned by various private and government entities, and which currently purchases energy and capacity from other IPPs in addition to our Olkaria III complex. The electricity sector is regulated by the ERC which was created under the Kenyan Energy Act. KPLC’s retail electricity rates are subject to approval by the ERC. The ERC has an expanded mandate to regulate not just the electric power sector but the entire energy sector in Kenya. Transmission of electricity is now undertaken by KETRACO while another company, GDC, is responsible for geothermal assessment, drilling of wells and sale of steam for electricity operations to IPPs and KenGen. Both KETRACO and GDC are wholly owned by the government of Kenya. Under the new national constitution enacted in August 2010, formulation of energy policy (including electricity) and energy regulation are functions of the national government. However, the constitution lists the planning and development of electricity and energy regulation as a function of the county governments (i.e. the regional or local level where an individual power plant is or is intended to be located).
Indonesia. The 2009 Electricity Law divided the power business into two broad categories: (1)
Honduras. In 2014, Honduras approved its new Law of Electrical Industry (Decree 404-2013), which provides the legal framework for the electricity sector and replaces the previous Electricity Subsector Framework Law (Decree 158 of 1994, regulated by Accord 934 of 1997). The Law establishes technology-specific auctions for renewable energy. It creates the Regulatory Commission of Electric Power (CREE) as the entity in charge of supervising the bidding processes and the awarding of PPAs. The CREE is also responsible for granting study permits for the construction of generation projects that use renewable natural resources. Permits will have a maximum duration of two years, and will be revoked if no studies have been initiated within a period of six months and the reports required by the CREE have not been submitted. The new Law also establishes that all new capacity must be contracted through auctions and that the government can set a minimum quota for renewables in each auction. With respect to metering, after previous regulation applied legal incentives to renewable energy metering, the new law mandates utilities to buy excess power and credit it towards monthly bills and to install bi-directional meters. Among others, the objectives of the law are to adapt the electricity sector’s legislation to the Framework Treaty for the Central American Electricity Market, which Honduras is a party to, and update the operating rules in the country’s electricity industry by incorporating structures and modern practices to increase the sector’s efficiency and competency in the production and marketing of electricity services.
With the passage of this new law, Honduras is moving into a new and open market. Under this legislation, all aspects of the market have been opened to private parties. This legislation is still being implemented within the market. Honduras has also approved a Law of Incentives for Renewable Energy Projects, Decree 70-2007, further amended by Decree 138-2013, with additional incentives to solar PV projects, etc. The purpose, as in other countries of the region, is to promote the development of renewable energy power plants. Laws provide certain benefits to companies that generate power through renewable sources, including a 10-year exemption from corporate income tax and VAT on imports and customs duties, a fast track process for certain permits and a Sovereign Guaranty by the Central Government for the payments of the off-taker, the Public Utility Company, ENEE. At present, the Law of the Electrical Industry and the Laws of Incentives for Renewable Energy Projects are still in force.
Because of the following factors, as well as other variables affecting our business, operating results or financial condition, past financial performance may not be a reliable indicator of future performance, and historical trends should not be used to anticipate results or trends in future periods. Concentration of customers may expose us to heightened financial exposure. We often rely on single customers at our facilities, exposing such facilities to financial risks if any customer should fail to perform its obligations. Our businesses often rely on a single customer to purchase all or a significant portion of a facility’s output. The financial performance of these facilities depends on such customer continuing to perform its obligations under the long-term agreement. A facility’s financial results could be materially and adversely affected if any of our customer fails to fulfill its contractual obligations and we are unable to find other customers to produce the same level of profitability. We cannot assure that such performance failures by third parties will not occur, or that if they do occur, such failures will not adversely affect the cash flows or profitability of our businesses. For example, we are exposed to the credit and financial condition of SCPPA and its municipal utility members, as customers that buy the output from six of our geothermal power plant. Because our contracts with SCPPA are long-term, we may be adversely affected if the credit quality of any of these customers were to decline or if their respective financial conditions were to deteriorate or if they are otherwise unable to perform their obligations under our long-term contracts. A significant portion of our Product segment revenues are concentrated in one region and expose us to regional economic or market declines. A significant portion of our Product segment revenues are concentrated in Turkey and rely on the continued geothermal development growth and government support for geothermal development in the country. Adverse political developments in the relationship between Turkey and the U.S., adverse economic developments in this region or a decline in government support for the development of geothermal power in the country could materially and adversely affect regional demand for the geothermal equipment and services we provide in the Turkish market or the prices we may charge for such equipment and services, which in turn could materially and adversely affect our Product segment profit margins and, consequently, our business, financial condition, future results and cash flows.
Our financial performance depends on the successful operation of our geothermal power and REG plants, which is subject to various operational risks.
Our financial performance depends on the successful operation of our subsidiaries’ geothermal and REG power plants. In connection with such operations, we derived approximately
Any of these events could significantly increase the expenses incurred by our power plants or reduce the overall generating capacity of our power plants and could significantly reduce or entirely eliminate the revenues generated by one or more of our power plants, which in turn would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flow.
As mentioned above, the aging of our power plants may reduce their availability and increase maintenance costs due to the need to repair or replace our equipment.
Our exploration, development, and operation of geothermal energy resources are subject to geological risks and uncertainties, which may result in decreased performance or increased costs for our power plants.
Our primary business involves the exploration, development, and operation of geothermal energy resources. These activities are subject to uncertainties that, in certain respects, are similar to those typically associated with oil and gas exploration, development, and exploitation, such as dry holes, uncontrolled releases, and pressure and temperature decline. Any of these uncertainties may increase our capital expenditures and our operating costs, or reduce the efficiency of our power plants. We may not find geothermal resources capable of supporting a commercially viable power plant at exploration sites where we have conducted tests, acquired land rights, and drilled test wells, which would adversely affect our development of geothermal power plants. Further, since the commencement of their operations, several of our power plants have experienced geothermal resource cooling, uncontrolled flow and/or reservoir pressure decline in the normal course of operations.
Another aspect of geothermal operations is the management and stabilization of subsurface impacts caused by fluid injection pressures of production and injection fluids to mitigate subsidence. In the case of the geothermal resource supplying the Heber complex, pressure drawdown in the center of the well field has caused some localized ground subsidence, while pressure in the peripheral areas has caused localized ground inflation. Inflation and subsidence, if not controlled, can adversely affect farming operations and other infrastructure at or near the land surface. Potential costs, which cannot be estimated and may be significant, of failing to stabilize site pressures in the Heber complex area include repair and modification of gravity-based farm irrigation systems and municipal sewer piping and possible repair or replacement of a local road bridge spanning an irrigation canal.
Additionally, active geothermal areas, such as the areas in which our power plants are located, are subject to frequent low-level seismic disturbances, volcanic eruptions and lava flows. Serious seismic disturbances, volcanic eruptions and lava flows are possible and could result in damage to our power plants (or transmission lines used by customers who buy electricity from us) or equipment or degrade the quality of our geothermal resources to such an extent that we could not perform under the PPA for the affected power plant, which in turn could reduce our net income and materially and adversely affect our business, financial condition, future results and cash flow. If we suffer a serious seismic disturbance, volcanic eruptions and lava flows, our business interruption and property damage insurance may not be adequate to cover all losses sustained as a result thereof. In addition, insurance coverage may not continue to be available in the future in amounts adequate to insure against such seismic disturbances, volcanic eruptions and lava flows.
Furthermore, absent additional geologic/hydrologic studies, any increase in power generation from our geothermal power plants, failure to reinject the geothermal fluid or improper maintenance of the hydrological balance may affect the operational duration of the geothermal resource and cause it to decline in value over time, and may adversely affect our ability to generate power from the relevant geothermal power plant.
Reduced levels of recovered energy required for the operation of our REG power plants may result in decreased performance of such power plants.
Our REG power plants generate electricity from recovered energy or so-called “waste heat” that is generated as a residual by-product of gas turbine-driven compressor stations and a variety of industrial processes. Any interruption in the supply of the recovered energy source, such as a result of reduced gas flows in the pipelines or reduced level of operation at the compressor stations, or in the output levels of the various industrial processes, may cause an unexpected decline in the capacity and performance of our recovered energy power plants.
Our business development activities may not be successful and our projects under construction may not commence operation as scheduled.
We are in the process of developing and constructing a number of new power plants. Our success in developing a particular project is contingent upon, among other things, negotiation of satisfactory engineering and construction agreements and obtaining PPAs and transmission services agreements, receipt of required governmental permits, obtaining adequate financing, and the timely implementation and satisfactory completion of field development, testing and power plant constructionand commissioning. We may be unsuccessful in accomplishing any of these matters or doing so on a timely basis. Although we may attempt to minimize the financial risks attributable to the development of a project by securing a favorable PPA and applicable transmission services agreements, obtaining all required governmental permits and approvals and arranging, in certain cases, adequate financing prior to the commencement of construction, the development of a power project may require us to incur significant expenses for preliminary engineering, permitting and legal and other expenses before we can determine whether a project is feasible, economically attractive or capable of being financed.
Currently, we have geothermal projects and prospects under exploration, development or construction in the U.S., Kenya, Guatemala, Guadeloupe, New Zealand, Honduras, Indonesia and Ethiopia, and we intend to pursue the expansion of some of our existing plants and the development of other new plants. Our completion of these facilities is subject to substantial risks, including:
Any one of these could give rise to delays, cost overruns, the termination of the plant expansion, construction or development or the loss (total or partial) of our interest in the project under development, construction, or expansion.
We rely on power transmission facilities that we do not own or control.
We depend on transmission facilities owned and operated by others to deliver the power we sell from our power plants to our customers. If transmission is disrupted, or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver power to our customers may be adversely impacted and we may either incur additional costs or forego revenues. In addition, lack of access to new transmission capacity may affect our ability to develop new projects. Existing congestion of transmission capacity, as well as expansion of transmission systems and competition from other developers seeking access to expanded systems, could also affect our performance.
We may be unable to obtain the financing we need to pursue our growth strategy and any future financing we receive may be less favorable to us than our current financing arrangements, either of which may adversely affect our ability to expand our operations.
Most of our geothermal power plants generally have been financed using leveraged financing structures, consisting of non-recourse or limited recourse debt obligations. Each of our projects under development or construction and those projects and businesses we may seek to acquire or construct will require substantial capital investment. Our continued access to capital
Market conditions and other factors may not permit future project and acquisition financings on terms similar to those our subsidiaries have previously received. Our ability to arrange for financing on a substantially non-recourse or limited recourse basis, and the costs of such financing, are dependent on numerous factors, including general economic conditions, conditions in the global capital and credit markets, investor confidence, the continued success of current power plants, the credit quality of the power plants being financed, the political situation in the country where the power plant is located, and the continued existence of tax and securities laws which are conducive to raising capital. If we are not able to obtain financing for our power plants on a substantially non-recourse or limited recourse basis, we may have to finance them using recourse capital such as direct equity investments or the incurrence of additional debt by us.
Also, in the absence of favorable financing options, we may decide not to build new plants or acquire facilities from third parties. Any of these alternatives could have a material adverse effect on our growth prospect
We may also need additional financing to implement our strategic plan. For example, our cash flow from operations and existing liquidity facilities may not be adequate to finance any acquisitions we may want to pursue or new technologies we may want to develop or acquire. Financing for acquisitions or
Our use of joint ventures may limit our flexibility with jointly owned investments.
We have sold minority equity interests in four of our consolidated subsidiaries, through which we hold a large number of our domestic geothermal power plants and recovered energy generation plants, to different third parties and we have partners that hold a minority equity interest in our geothermal power plant in Guadeloupe. We may continue in the future to develop and/or acquire and/or hold properties in joint ventures with other entities when circumstances warrant the use of these structures. Ownership of assets in joint ventures is subject to risks that may not be present with other methods of ownership, including:
Our international operations expose us to risks related to the application of foreign laws, taxes, economic conditions, labor supply and relations, political conditions, and policies of foreign governments, any of which may adversely affect our business, financial condition, future results and cash flow.
We have substantial operations outside of the U.S., both in our Electricity segment and our Product segment. Our foreign operations are subject to regulation by various foreign governments and regulatory authorities and are subject to the application of foreign laws. Such foreign laws or regulations may not provide the same type of legal certainty and rights, in connection with our contractual relationships in such countries, as are afforded to our operations in the U.S., which may adversely affect our ability to receive revenues or enforce our rights in connection with our foreign operations. Furthermore, existing laws or regulations may be amended or repealed, and new laws or regulations may be enacted or issued. In addition, the laws and regulations of some countries may limit our ability to hold a majority interest in some of the power plants that we may develop or acquire, thus limiting our ability to control the development, construction and operation of such power plants, or our ability to import our products into such countries. Our foreign operations are also subject to significant political, economic and financial risks, which vary by country, and include:
In particular, With respect
Any or all of the changes discussed above could materially and adversely affect our business, financial condition, future results and cash flow.
Our foreign power plants and foreign manufacturing operations expose us to risks related to fluctuations in currency rates, which may reduce our profits from such power plants and operations.
Risks attributable to fluctuations in currency exchange rates can arise when 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 addition, the imposition by foreign governments of restrictions on the transfer of foreign currency abroad, or restrictions on the conversion of local currency into foreign currency, would have an adverse effect on the operations of our foreign power plants and foreign manufacturing operations, and may limit or diminish the amount of cash and income that we receive from such foreign power plants and operations.
A significant portion of our electricity revenues is attributed to payments made by power purchasers under PPAs. The failure of any such power purchaser to perform its obligations under the relevant PPA or the loss of a PPA due to a default would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flow.
A significant portion of our revenues is Storage projects that we are currently developing or plan to develop in the future may operate as "merchant" facilities without long-term power sales agreements for some or all of their generating capacity and output and therefore such projects will be exposed to market fluctuations. Storage projects that we are currently developing or plan to develop in the future may operate as "merchant" facilities without long-term sales agreements for some or all of their generating capacity and output and therefore such projects will be exposed to market fluctuations. Without the benefit of long-term sales agreements for these assets, we cannot be sure that we will be able to sell any or all of the power and ancillary services generated by these facilities at commercially attractive rates or that these facilities will be able to operate profitably. This could lead to future impairments of our property, plant and equipment or to the closing of certain of our storage facilities, resulting in economic losses and liabilities, which could have a material adverse effect on our results of operations, financial condition or cash flows.
Seasonal variations may cause fluctuations in our cash flows, which may cause the market price of our common stock to fall in certain periods.
Our results of operations are subject to seasonal variations. This is primarily because some of our power plants may experience reduced generation during warm periods due to the lower heat differential between the geothermal fluid and the ambient surroundings. Some of our domestic power plants receive higher capacity payments under the relevant PPAs during the summer months, and due to the generally higher time-of-use energy factor during the summer months.
Pursuant to the terms of some of our PPAs with investor-owned electric utilities and publicly-owned electric utilities in states that have renewable portfolio standards, the failure to supply the contracted capacity and energy thereunder may result in the imposition of penalties.
Pursuant to the terms of certain of our PPAs, we may be required to make payments to the relevant power purchaser under certain conditions, such as shortfall in delivery of renewable energy and energy credits, and not meeting certain performance threshold requirements, as defined in the relevant PPA. The amount of payment required is dependent upon the level of shortfall in delivery or performance requirements and is recorded in the period the shortfall occurs. In addition, if we do not meet certain minimum performance requirements, the capacity of the relevant power plant may be permanently reduced. Any or all of these considerations could materially and adversely affect our business, financial condition, future results and cash flow.
The Energy Choice Initiative (ECI), a pending amendment to the Constitution of the State of Nevada, may permit our customer to terminate its PPAs with us. The ECI is a proposed amendment to the Constitution of the State of Nevada that would require the Nevada Legislature to adopt new statutes or amend existing statutes in order to establish an open and competitive retail electricity market and prevent the concentration of the electricity generation market among only a few generators of electricity. This ballot question passed with over 72% of Nevada voters in favor in November 2016, and if it passes again in November 2018, the Nevada Legislature will be required to amend state law in the manner described above by no later than 2023. It is unclear what impact the ECI would have on our existing PPAs and the Nevada RPS. NV Energy, the offtaker of our Brady, SB Complex, Tuscarora, Jersey Valley and McGinness Hills power plants, is taking the position that the ECI would require the termination of our existing PPAs and potentially the termination of the RPS. Whether existing PPAs could be terminated will remain unclear until the scope of the Nevada Legislature’s implementation of the ECI becomes known. If the Nevada Legislature adopts any new laws pursuant to the ECI that terminate or require the termination of, our existing PPAs with NV Energy, we could lose significant amounts of revenue derived from the sale of electricity to NV Energy under such PPAs which could materially and adversely affect our business, financial condition, future results and cash flow.
The SRAC for our power purchasers may decline, which would reduce our power plant revenues and could materially and adversely affect our business, financial condition, future results and cash flow.
Under
Under the terms of a global settlement approved by CPUC (Global Settlement) SRAC for our
If any of our domestic power plants loses its current Qualifying Facility status under PURPA, or if amendments to PURPA are enacted that substantially reduce the benefits currently afforded to Qualifying Facilities, our domestic operations could be adversely affected.
Most of our domestic power plants are Qualifying Facilities pursuant to PURPA, which largely exempts the power plants from the FPA, and certain state and local laws and regulations regarding rates and financial and organizational requirements for electric utilities.
If any of our domestic power plants were to lose its Qualifying Facility status, such power plant could become subject to the full scope of the FPA and applicable state regulation. The application of the FPA and other applicable state regulation to our domestic power plants could require our operations to comply with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility.
If a domestic power plant were to lose its Qualifying Facility status, it would become subject to full regulation as a public utility under the FPA, and the rates charged by such power plant pursuant to its PPAs would be subject to the review and approval of FERC. FERC, upon such review, may determine that the rates currently set forth in such PPAs are not appropriate and may set rates that are lower than the rates currently charged. In addition, FERC may require that the affected domestic power plant refund amounts previously paid by the relevant power purchaser to such power plant. Even if a power plant does not lose its Qualifying Facility status, pursuant to regulations issued by FERC for Qualifying Facility power plants above 20 MW, if a power plant’s PPA is terminated or otherwise expires, and the subsequent sales are not made pursuant to a state’s implementation of PURPA, that power plant will become subject to FERC’s ratemaking jurisdiction under the FPA. Moreover, a loss of Qualifying Facility status also could permit the power purchaser, pursuant to the terms of the particular PPA, to cease taking and paying for electricity from the relevant power plant or, consistent with FERC precedent, to seek refunds of past amounts paid. This could cause the loss of some or all of our revenues payable pursuant to the related PPAs, result in significant liability for refunds of past amounts paid, or otherwise impair the value of our power plants. If a power purchaser were to cease taking and paying for electricity or seek to obtain refunds of past amounts paid, there can be no assurance that the costs incurred in connection with the power plant could be recovered through sales to other purchasers or that we would have sufficient funds to make such payments. In addition, the loss of Qualifying Facility status would be an event of default under the financing arrangements currently in place for some of our power plants, which would enable the lenders to exercise their remedies and enforce the liens on the relevant power plant.
Pursuant to the Energy Policy Act of 2005, FERC also has the authority to prospectively lift the mandatory obligation of a utility under PURPA to offer to purchase the electricity from a Qualifying Facility if the utility operates in a workably competitive market. Our existing PPAs between a Qualifying Facility and a utility are not affected. If, in addition to the California utilities’ waiver of the mandatory purchase obligation for QF projects that exceed 20 MW described in the risk factor above,
The reduction or elimination of government incentives could adversely affect our business, financial condition, future results and cash flows.
Construction and operation of our geothermal power plants and recovered energy-based power plants has benefited, and may benefit in the future, from public policies and government incentives that support renewable energy and enhance the economic feasibility of these projects in regions and countries where we operate. Such policies and incentives include PTCs and ITCs, accelerated depreciation tax benefits, renewable portfolio standards, carbon trading mechanisms, rebates, and mandated feed-in-tariffs, and may include similar or other incentives to end users, distributors, system integrators and manufacturers of geothermal, solar and other power products. Some of these measures have been implemented at the federal level, while others have been implemented by different states within the U.S. or countries outside the U.S. where we operate.
The availability and continuation of these public policies and government incentives have a significant effect on the economics and viability of our development program and continued construction of new geothermal, recovered energy-based, Solar PV power plants and, recently, energy storage projects. Any changes to such public policies, or any reduction in or elimination or expiration of such government incentives could affect us in different ways. For example, any reduction in, termination or expiration of renewable portfolio standards may result in less demand for generation from our geothermal and recovered energy-based, power plants. Any reductions in, termination or expiration of other government incentives could reduce the economic viability of, and cause us to reduce, the construction of new geothermal, recovered energy-based, Solar PV or any other power plants. Similarly, any such changes that affect the geothermal energy industry in a manner that is different from other sources of renewable energy, such as wind or solar, may put us at a competitive disadvantage compared to businesses engaged in the development, construction and operation of renewable power projects using such other resources. Any of the foregoing outcomes could have a material adverse effect on our business, financial condition, future results, and cash flows.
Our financial performance could be adversely affected by changes in the legal and regulatory environment affecting our power plants.
All of our power plants are subject to extensive regulation, and therefore changes in applicable laws or regulations, or interpretations of those laws and regulations, could result in increased compliance costs, the need for additional capital expenditures or the reduction of certain benefits currently available to our power plants. The structure of domestic and foreign federal, state and local energy regulation currently is, and may continue to be, subject to challenges, modifications, the imposition of additional regulatory requirements, and restructuring proposals. We or our power purchasers may not be able to obtain all regulatory approvals that may be required in the future, or any necessary modifications to existing regulatory approvals, or maintain all required regulatory approvals. In addition, the cost of operation and maintenance and the operating performance of geothermal power plants may be adversely affected by changes in certain laws and regulations, including tax laws.
Any changes to applicable laws and regulations could significantly increase the regulatory-related compliance and other expenses incurred by the power plants and could significantly reduce or entirely eliminate the revenues generated by one or more of the power plants, which in turn would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flow.
The costs of compliance with environmental laws and of obtaining and maintaining environmental permits and governmental approvals required for construction and/or operation may increase in the future and these costs (as well as any fines or penalties that may be imposed upon us in the event of any non-compliance with such laws or regulations) could materially and adversely affect our business, financial condition, future results and cash flow.
Environmental laws, ordinances and regulations affecting us can be subject to change and such change could result in increased compliance costs, the need for additional capital expenditures, or otherwise adversely affect us. In addition, our power plants are required to comply with numerous domestic and foreign, federal, regional, state and local statutory and regulatory environmental standards and to maintain numerous environmental permits and governmental approvals required for construction and/or operation. We may not be able to renew, maintain or obtain all environmental permits and governmental approvals required for the continued operation or further development of the power plants. We have not yet obtained certain permits and government approvals required for the completion and successful operation of power plants under construction or enhancement. Our failure to renew, maintain or obtain required permits or governmental approvals, including the permits and approvals necessary for operating power plants under construction or enhancement, could cause our operations to be limited or suspended. Finally, some of the environmental permits and governmental approvals that have been issued to the power plants contain conditions and restrictions, including restrictions or limits on emissions and discharges of pollutants and contaminants, or may have limited terms. If we fail to satisfy these conditions or comply with these restrictions, or with any statutory or regulatory environmental standards, we may become subject to regulatory enforcement action and the operation of the power plants could be adversely affected or be subject to fines, penalties or additional costs.
We could be exposed to significant liability for violations of hazardous substances laws because of the use or presence of such substances at our power plants.
Our power plants are subject to numerous domestic and foreign federal, regional, state and local statutory and regulatory standards relating to the use, storage and disposal of hazardous substances. We use butane, pentane, industrial lubricants, and other substances at our power plants which are or could become classified as hazardous substances. If any hazardous substances are found to have been released into the environment at or by the power plants in concentrations that exceed regulatory limits, we could become liable for the investigation and removal of those substances, regardless of their source and time of release. If we fail to comply with these laws, ordinances or regulations (or any change thereto), we could be subject to civil or criminal liability, the imposition of liens or fines, and large expenditures to bring the power plants into compliance. Furthermore, in the U.S., we can be held liable for the cleanup of releases of hazardous substances at other locations where we arranged for disposal of those substances, even if we did not cause the release at that location. The cost of any remediation activities in connection with a spill or other release of such substances could be significant.
We believe that at one time there may have been a gas station located on the Mammoth complex site, but because of significant surface disturbance and construction since that time, further physical evaluation of the environmental condition of the former gas station site has been impractical. There may be soil or groundwater contamination and related potential liabilities of which we are unaware related to this site, which may be significant and could materially and adversely affect our business, financial condition, future results and cash flow.
We may decide not to implement, or may not be successful in implementing, one or more elements of our multi-year strategic plan, and the plan as implemented may not achieve its goal to enhance shareholder value through long-term growth of the Company
We adopted a multi-year strategic plan to:
There are uncertainties and risks associated with the plan, both as to implementation and outcome. Implementation of the plan may be affected by a number of factors, including that:
For example, we
Expanding our geothermal and recovered energy businesses to new customers and geographical areas will have many of the same risks and uncertainties as those outlined above. These or other factors could mean that we decide to change or even abandon, or are otherwise unable to implement, one or more elements of the plan.
Implementing the plan
These costs may not be recovered, in whole or in part, if one or more elements of the plan are not successfully implemented. These costs, or the failure to implement successfully one or more elements of the plan, could adversely affect our reputation and the reputation of our
Apart from the risks associated with implementing the plan, the plan itself will expose us to other risks and uncertainties once implemented. For example, expanding our customer base may expose us to different credit profile customers than our current customers.
The trading price of our common stock could decline if securities, industry analysts or our investors disagree with our strategic plan or the way we implement it, either as a result of the factors outlined above or for other reasons.
Accordingly, there is no assurance that the plan will enhance shareholder value through long-term growth of the Company to the extent currently anticipated by our management or at all.
We may not be able to successfully integrate companies, which we acquired and may acquire in the future, which could materially and adversely affect our business, financial condition, future results and cash flow.
Our strategy is to continue to expand in the future, including through acquisitions. Integrating acquisitions is often costly, and we may not be able to successfully integrate our acquired companies with our existing operations without substantial costs, delays or other adverse operational or financial consequences. Integrating our acquired companies involves a number of risks that could materially and adversely affect our business, including:
If any of our acquired companies suffers customer dissatisfaction or performance problems, this could adversely affect the reputation of our group of companies and could materially and adversely affect our business, financial condition, future results and cash flow.
The power generation industry is characterized by intense competition, and we encounter competition from electric utilities, other power producers, and power marketers that could materially and adversely affect our business, financial condition, future results and cash flow.
The power generation industry is characterized by intense competition from electric utilities, other power producers and power marketers. In recent years, there has been increasing competition in the sale of electricity, in part due to excess capacity in a number of U.S. markets and an emphasis on short-term or “spot” markets, and competition has contributed to a reduction in electricity prices. For the most part, we expect that power purchasers interested in long-term arrangements will engage in “competitive bid” solicitations to satisfy new capacity demands. This competition could adversely affect our ability to obtain PPAs and the price paid for electricity by the relevant power purchasers. There is also increasing competition between electric utilities. This competition has put pressure on electric utilities to lower their costs, including the cost of purchased electricity, and increasing competition in the future will put further pressure on power purchasers to reduce the prices at which they purchase electricity from us.
We face increasing competition from other companies engaged in the solar, energy storage, demand response and energy
The solar power market is intensely competitive and rapidly evolving. We compete with many companies that have longer operating histories in this sector, larger customer bases, and greater brand recognition, as well as, in some cases, significantly greater financial and marketing resources than us. In some cases, these competitors are vertically integrated in the solar energy sector, manufacturing Solar PV, silicon wafers, and other related products for the solar industry, which may give them an advantage in developing, constructing, owning and operating solar power projects. Our limited experience in the Solar PV sector may affect our ability to successfully develop, construct, finance, and operate Solar PV power projects.
While our Viridity business
The existence of a prolonged force majeure event or a forced outage affecting a power plant or the transmission system of the IID could reduce our net income and materially and adversely affect our business, financial condition, future results and cash flow.
The operation of our subsidiaries’ geothermal power plants is subject to a variety of risks discussed elsewhere in these risk factors, including events such as fires, explosions, earthquakes, landslides, floods, severe storms, volcanic eruptions, lava flow or other similar events. If a power plant experiences an occurrence resulting in a force majeure event, although our subsidiary that owns that power plant would be excused from its obligations under the relevant PPA, the relevant power purchaser may not be required to make any capacity and/or energy payments with respect to the affected power plant
In addition, if the transmission system of the IID experiences a force majeure event or a forced outage which prevents it from transmitting the electricity from the Heber complex, the Ormesa complex or the North Brawley power plant to the relevant power purchaser, the relevant power purchaser would not be required to make energy payments for such non-delivered electricity and may not be required to make any capacity payments with respect to the affected power plant
Some of our leases will terminate if we do not extract geothermal resources in “commercial quantities”, thus requiring us to enter into new leases or secure rights to alternate geothermal resources, none of which may be available on terms as favorable to us as any such terminated lease, if at all.
Most of our geothermal resource leases are for a fixed primary term, and then continue for so long as geothermal resources are extracted in “commercial quantities” or pursuant to other terms of extension. The land covered by some of our leases is undeveloped and has not yet produced geothermal resources in commercial quantities. Leases that cover land which remains undeveloped and does not produce, or does not continue to produce, geothermal resources in commercial quantities and leases that we allow to expire, will terminate. In the event that a lease is terminated and we determine that we will need that lease once the applicable power plant is operating, we would need to enter into one or more new leases with the owner(s) of the premises that are the subject of the terminated lease(s) in order to develop geothermal resources from, or inject geothermal resources into, such premises or secure rights to alternate geothermal resources or lands suitable for injection. We may not be able to do this or may not be able to do so without incurring increased costs, which could materially and adversely affect our business, financial condition, future results and cash flow.
Our BLM leases may be terminated if we fail to comply with any of the provisions of the Geothermal Steam Act or if we fail to comply with the terms or stipulations of such leases, which could materially and adversely affect our business, financial condition, future results and cash flow.
Pursuant to the terms of our BLM leases, we are required to conduct our operations on BLM-leased land in a workmanlike manner and in accordance with all applicable laws and BLM directives and to take all mitigating actions required by the BLM to protect the surface of and the environment surrounding the relevant land. Additionally, certain BLM leases contain additional requirements, some of which relate to the mitigation or avoidance of disturbance of any antiquities, cultural values or threatened or endangered plants or animals. In the event of a default under any BLM lease, or the failure to comply with such requirements, or any non-compliance with any of the provisions of the Geothermal Steam Act or regulations issued thereunder, the BLM may, 30 days after notice of default is provided to our relevant project subsidiary, suspend our operations until the requested action is taken or terminate the lease, either of which could materially and adversely affect our business, financial condition, future results and cash flow.
Some of our leases (or subleases) could terminate if the lessor (or sublessor) under any such lease (or sublease) defaults on any debt secured by the relevant property, thus terminating our rights to access the underlying geothermal resources at that location.
The fee interest in the land which is the subject of some of our leases (or subleases) may currently be or may become subject to encumbrances securing loans from third-party lenders to the lessor (or sublessor). Our rights as lessee (or sublessee) under such leases (or subleases) are or may be subject and subordinate to the rights of any such lender. Accordingly, a default by the lessor (or sublessor) under any such loan could result in a foreclosure on the underlying fee interest in the property and thereby terminate our leasehold interest and result in the shutdown of the power plant located on the relevant property and/or terminate our right of access to the underlying geothermal resources required for our operations.
In addition, a default by a sublessor under its lease with the owner of the property that is the subject of our sublease could result in the termination of such lease and thereby terminate our sublease interest and our right to access the underlying geothermal resources required for our operations.
Current and future urbanizing activities and related residential, commercial, and industrial developments may encroach on or limit geothermal or Solar PV activities in the areas of our power plants, thereby affecting our ability to utilize access, inject and/or transport geothermal resources on or underneath the affected surface areas.
Current and future urbanizing activities and related residential, commercial and industrial development may encroach on or limit geothermal activities in the areas of our power plants or construction and operation of Solar PV facilities, thereby affecting our ability to utilize, access, inject, and/or transport geothermal resources on or underneath the affected surface areas or build Solar PV facilities, which require large areas of relatively flat land. In particular, the Heber power plants rely on an area, which we refer to as the Heber Known Geothermal Resource Area, or Heber KGRA, for the geothermal resource necessary to generate electricity at the Heber power plants. Imperial County has adopted a “specific plan area” that covers the Heber KGRA, which we refer to as the “Heber Specific Plan Area”. The Heber Specific Plan Area allows commercial, residential, industrial and other employment oriented development in a mixed-use orientation, which currently includes geothermal uses. Several of the landowners from whom we hold geothermal leases have expressed an interest in developing their land for residential, commercial, industrial or other surface uses in accordance with the parameters of the Heber Specific Plan Area. Currently, Imperial County’s Heber Specific Plan Area is coordinated with the cities of El Centro and Calexico. There has been ongoing underlying interest since the early 1990s to incorporate the community of Heber. While any incorporation process would likely take several years, if Heber were to be incorporated, the City of Heber could replace Imperial County as the governing land use authority, which, depending on its policies, could have a significant effect on land use and availability of geothermal resources.
Current and future development proposals within Imperial County and the City of Calexico, applications for annexations to the City of Calexico, and plans to expand public infrastructure may affect surface areas within the Heber KGRA, thereby limiting our ability to utilize, access, inject and/or transport the geothermal resource on or underneath the affected surface area that is necessary for the operation of our Heber power plants, which could adversely affect our operations and reduce our revenues.
Current construction works and urban developments in the vicinity of our Steamboat complex of power plants in Nevada may also affect future permitting for geothermal operations relating to those power plants. Such works and developments include plans for the construction of a new casino hotel and other commercial or industrial developments on land in the vicinity of our Steamboat complex.
We depend on key personnel for the success of our business.
In general, our success depends to a significant extent on the performance of our senior management, particularly the continued service of our key employees. Our success also depends on our ability to identify, hire and retain other qualified and experienced key personnel. Although to date we have been successful in identifying, hiring and retaining the services of senior management, we face risks associated with our ability to locate or employ on acceptable terms qualified replacements for our senior management or key employees if their services were no longer available, and with the inherent difficulties and uncertainties of transitioning the Company under the leadership of new management.
In the demand response industry, there is a relatively small pool of experienced personnel. In the relatively new energy storage market, there is an even smaller pool of experienced personnel. Our plans to grow the Viridity business
Our inability to successfully identify, hire and retain any key employee could materially
Our power plants have generally been financed through a combination of our corporate funds and limited or non-recourse project finance debt and lease financing. If our project subsidiaries default on their obligations under such limited or non-recourse debt or lease financing, we may be required to make certain payments to the relevant debt holders, and if the collateral supporting such leveraged financing structures is foreclosed upon we may lose certain of our power plants.
Our power plants have generally been financed using a combination of our corporate funds and limited or non-recourse project finance debt or lease financing. Limited recourse project finance debt refers to our additional agreement, as part of the financing of a power plant, to provide limited financial support for the power plant subsidiary in the form of limited guarantees, indemnities, capital contributions and agreements to pay certain debt service deficiencies. Non-recourse project finance debt or lease financing refers to financing arrangements that are repaid solely from the power plant’s revenues and are secured by the power plant’s physical assets, major contracts, cash accounts and, in many cases, our ownership interest in the project subsidiary. If our project subsidiaries default on their obligations under the relevant debt documents, creditors of a limited recourse project financing will have direct recourse to us, to the extent of our limited recourse obligations, which may require us to use distributions received by us from other power plants, as well as other sources of cash available to us, in order to satisfy such obligations. In addition, if our project subsidiaries default on their obligations under the relevant debt documents (or a default under such debt documents arises as a result of a cross-default to the debt documents of some of our other power plants) and the creditors foreclose on the relevant collateral, we may lose our ownership interest in the relevant project subsidiary or our project subsidiary owning the power plant would only retain an interest in the physical assets, if any, remaining after all debts and obligations were paid in full.
Changes in costs and technology may significantly impact our business by making our power plants and products less competitive.
A basic premise of our business model is that generating baseload power at geothermal power plants
Our expectations regarding the market potential for the development of recovered energy-based power generation may not materialize, and as a result we may not derive any significant revenues from this line of business.
Demand for our recovered energy-based power generation units may not materialize or grow at the levels that we expect. We currently face competition in this market from manufacturers of conventional steam turbines and may face competition from other related technologies in the future. If this market does not materialize at the levels that we expect, we will not generate any material revenues.
Our intellectual property rights may not be adequate to protect our business.
Our existing intellectual property rights,
In order to safeguard our unpatented proprietary know-how, trade secrets and technology, we rely primarily upon trade secret protection and non-disclosure provisions in agreements with employees and others having access to confidential information. These measures may not adequately protect us from disclosure or misappropriation of our proprietary information.
Even if we adequately protect our intellectual property rights, litigation may be necessary to enforce these rights, which could result in substantial costs to us and a substantial diversion of management attention. Also, while we have attempted to ensure that our technology and the operation of our business do not infringe other parties’ patents and proprietary rights, our competitors or other parties may assert that certain aspects of our business or technology may be covered by patents held by them. Infringement or other intellectual property claims, regardless of merit or ultimate outcome, can be expensive and time-consuming and can divert management’s attention from our core business.
Threats of terrorism and catastrophic events that could result from terrorism, cyber-attacks, or individuals and/or groups attempting to disrupt our business, or the businesses of third parties, may impact our operations in unpredictable ways and could adversely affect our business, financial condition, future results and cash flow.
We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyber-attacks, including, among others, malware, viruses and attachments to e-mails, and other disruptive activities of individuals or groups. Our generation and transmission facilities, information technology systems and other infrastructure facilities, systems and physical assets,
We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite our implementation of security measures, all of our technology systems (and any programs or data stored thereon or therein) are vulnerable to security breaches, failures, data leakage or unauthorized access due to such activities. Those breaches and events may result from acts of our employees, contractors or third parties. If our technology systems were to fail or be breached and we were unable to recover in a timely way, we would be unable to fulfill critical business functions, and sensitive confidential and other data could be compromised, which could adversely affect our business, financial condition, future results and cash flow.
The implementation of security guidelines and measures and maintenance of insurance, to the extent available, addressing such activities could increase costs. These types of events could adversely affect our business, financial condition, future results and cash flow. In addition such events could require significant management attention and resources and could adversely affect our reputation among customers and the public.
A disruption of transmission or the transmission infrastructure facilities of third parties could negatively impact our business. Because generation and transmission systems are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the impact of an event on the interconnected system within our systems or within a neighboring system. Any such disruption could adversely affect our business, financial condition, future results and cash flow.
Possible fluctuations in the cost of construction, raw materials, commodities and drilling may materially and adversely affect our business, financial condition, future results, and cash flow.
Our manufacturing operations are dependent on the supply of various raw materials, including primarily steel and aluminum, commodities and industrial equipment components that we use. We currently obtain all such raw materials, commodities and equipment at prevailing market prices. We are not dependent on any one supplier and do not have any long-term agreements with any of our suppliers. Future cost increases of such raw materials, commodities and equipment, to the extent not otherwise passed along to our customers, could adversely affect our profit margins.
Conditions in and around Israel, where the majority of our senior management and our main production and manufacturing facilities are located, may adversely affect our operations and may limit our ability to produce and sell our products or manage our power plants.
The majority of our senior management and our main production and manufacturing facilities are located in Israel. As such, political, economic and security conditions in Israel directly affect our operations.
Since the establishment of the State of Israel in 1948, a number of armed conflicts have taken place between Israel and its Arab neighbors, and the continued state of hostility, varying in degree and intensity, has led to security and economic problems for Israel.
Negotiations between Israel and representatives of the Palestinian Authority in an effort to resolve the state of conflict have been sporadic and have failed to result in peace. The establishment in 2006 of a government in the Gaza territory by representatives of the Hamas militant group has created additional unrest and uncertainty in the region. In each of December 2008, November 2012 and July 2014, Israel engaged in an armed conflict with Hamas, each of which involved additional missile strikes from the Gaza Strip into Israel and disrupted most day-to-day civilian activity in the proximity of the border with the Gaza Strip. Our production facilities in Israel are located approximately 26 miles from the border with the Gaza Strip.
The political instability and civil unrest in the Middle East and North Africa (including the ongoing civil war in Syria) as well as the increased tension between Iran and Israel have raised new concerns regarding security in the region and the potential for armed conflict or other hostilities involving Israel. We could be adversely affected by any such hostilities, the interruption or curtailment of trade between Israel and its trading partners, or a significant downturn in the economic or financial condition of Israel. In addition, the sale of products manufactured in Israel may be adversely affected in certain countries by restrictive laws, policies or practices directed toward Israel or companies having operations in Israel.
In addition, some of our employees in Israel are subject to being called upon to perform military service in Israel, and their absence may have an adverse effect upon our operations. Generally, unless exempt, male adult citizens of Israel under the age of 41 are obligated to perform up to 36 days of military reserve duty annually. Additionally, all such citizens are subject to being called to active duty at any time under emergency circumstances.
These events and conditions could disrupt our operations in Israel, which could materially
We are a holding company and our revenues depend substantially on the performance of our subsidiaries and the power plants they operate, most of which are subject to restrictions and taxation on dividends and distributions.
We are a holding company whose primary assets are our ownership of the equity interests in our subsidiaries. We conduct no other business and, as a result, we depend entirely upon our subsidiaries’ earnings and cash flow.
The agreements pursuant to which most of our subsidiaries have incurred debt restrict the ability of these subsidiaries to pay dividends, make distributions or otherwise transfer funds to us prior to the satisfaction of other obligations, including the payment of operating expenses, debt service and replenishment or maintenance of cash reserves. In the case of some of our power plants that are owned jointly with other partners, there may be certain additional restrictions on dividend distributions pursuant to our agreements with those partners. We have identified a material weakness in our internal control over financial reporting which, if not timely remediated, may adversely affect the accuracy and reliability of our financial statements, and our reputation, business and the price of our common stock, as well as lead to a loss of investor confidence in us. In connection with the change in our repatriation strategy and the related release of the US income tax valuation allowance in the second quarter of 2017, we did not perform an effective risk assessment related to our internal controls over the accounting for income taxes. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim consolidated financial statements will not be prevented or detected on a timely basis. While we have developed and are in the process of implementing a remediation plan to remediate this material weakness and believe, based on our most recent assessment, that this material weakness will be remediated during 2018, there can be no assurance that this will occur within the expected timeline. We may identify additional material weaknesses in our internal control over financial reporting in the future. If we are unable to remediate this material weakness or we identify additional material weaknesses in our internal control over financial reporting in the future, our ability to analyze, record and report financial information accurately, to prepare our financial statements within the time periods specified by the rules and forms of the SEC and to otherwise comply with our reporting obligations under the federal securities laws, will likely be adversely affected. The occurrence of, or failure to remediate, this material weakness and any future material weaknesses in our internal control over financial reporting may adversely affect the accuracy and reliability of our financial statements, and our reputation, business and the price of our Common Stock or any other securities we may issue, as well as lead to a loss of investor confidence in us. U.S. federal income tax reform could adversely affect us. On December 22, 2017, U.S. federal tax legislation, commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) was signed into law, significantly reforming the U.S. Internal Revenue Code. The Tax Act, among other things, includes changes to U.S. federal tax rates (including reduction of the corporate tax rate from 35% to 21%), imposes significant additional limitations on the deductibility of interest, allows for the expensing of capital expenditures, puts into effect the migration from a “worldwide” system of taxation to a territorial system and modifies or repeals many business deductions and credits. The Tax Act is likely to make some borrowing more expensive. It denies interest deductions on debt starting in 2018 to the extent a company's net interest expense exceeds 30 percent of its adjusted taxable income. Its income for this purpose means income ignoring interest expense, interest income, net operating losses and -- only through 2021 -- depreciation, amortization and depletion. Thus, the 30-percent limit is more likely to come into play after 2021 when depreciation, amortization and depletion are no longer added back to the 30-percent base. Any interest that cannot be deducted in a year can be carried forward indefinitely.
The Tax Act subjects U.S. corporations with offshore subsidiaries to a one-time U.S. tax on untaxed earnings in offshore holding companies as if the earnings had been brought back to the U.S. thereby triggering a tax. All post-1986 net "earnings and profits" in offshore holding companies will be taxed at a 15.5 percent rate to the extent they are being held in cash or cash equivalents and at an eight percent rate otherwise. Companies must calculate the earnings as of November 2, 2017 and December 31, 2017 and pay U.S. tax on whichever amount is higher. The tax can be paid ratably over eight years. Eight percent of the tax would have to be paid in each of the first five years starting in 2017, increasing to 15 percent in year six, 20 percent in year seven and 25 percent in year eight. Corporations will no longer be able to use net operating losses incurred after 2017 to reduce income by more than 80 percent in a year, and corporations will no longer be able to carry such losses back two years as they have been allowed to do in the past. Starting in 2018, the U.S. will no longer allow some cross-border interest and royalty payments to related companies to be deducted. This would happen if the other country treats the payments as something other than interest or royalties for its tax purposes or the two countries treat the U.S. company making the payments differently: for example, one treats it as a corporation and the other treats it as fiscally transparent or vice versa. Once the provision is triggered, deductions would be denied in the U.S. to the extent the payment does not have to be reported as income in the foreign country. We continue to examine the impact the Tax Act may have on our business. 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. Possible application of the new base erosion anti-avoidance tax in the U.S. may adversely affect us. The recently enacted Tax Act in the U.S. included a base erosion and anti-abuse tax, or BEAT, that could apply to us and, more importantly, could reduce the amount of tax equity that can be raised on geothermal projects on which PTCs will be claimed. The aim of the base erosion tax is to prevent multinational companies from reducing their U.S. taxes by “stripping” earnings across the U.S. border by making payments to foreign affiliates that can be deducted in the U.S. An example of such a payment is interest on an intercompany loan or a payment to a back office in a foreign country for equipment or services. The goal of the base erosion tax is to ensure that multinational companies do not use cross-border payments to reduce their U.S. taxes to less than 10 percent of an expanded definition of taxable income. The base erosion tax requires an annual calculation. The tax only applies to companies with at least $500 million in average annual gross receipts in the three prior years before the calculation. If the tax applies to us, our tax equity raised on geothermal projects on which PTCs can be claimed may be reduced, which in turn may materially and adversely affect our business, financial condition, future results and cash flow.
The Israeli Tax Ruling we obtained in connection with our acquisition of Ormat Industries imposes conditions that may limit our flexibility in operating our business and our ability to enter into certain corporate transactions.
The Israel Tax Ruling we obtained in connection with the acquisition of Ormat Industries imposes a number of conditions that limit our flexibility in operating our business and in engaging in certain corporate transactions. Until the end of 2018, we agreed to maintain (and, to the extent that our operations expand, likewise expand) the production activities we currently carry out in Israel. Under certain circumstances, these conditions may not allow us the flexibility that we need to operate our business and may prevent us from taking advantage of strategic opportunities that would benefit our business and our stockholders.
As a result of these
The price of our common stock may fluctuate substantially, and your investment may decline in value.
The market price of our common stock may be highly volatile and may fluctuate substantially due to many factors, including:
In addition, the stock market in general, and the NYSE and the market for energy companies in particular, have experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of particular companies affected. These broad market and industry factors may materially harm the market price of our common stock, regardless of our operating performance. In the past, following periods of volatility in the market price of a company’s securities, securities class-action litigation has often been instituted against that company. Such litigation, if instituted against us, could result in substantial costs and a diversion of management’s attention and resources, which could materially harm our business, financial condition, future results and cash flow.
Regulations related to conflict minerals may force us to incur additional expenses and may damage our relationship with certain customers.
On August 22, 2012, the SEC adopted requirements regarding mandatory disclosure for companies regarding their use of "conflict minerals" (including tantalum, tin, tungsten and gold) in their products. In general, while we do not directly purchase or use any of these “conflict minerals” as raw materials in the products we manufacture or as part of our manufacturing processes, we will need to examine whether such minerals are contained in the products supplied to us by third parties and, if so, whether such minerals originate from the Democratic Republic of Congo or adjoining countries. If we utilize any of these minerals and they are necessary to the production or functionality of any of our products or products we are contracted to manufacture, we will need to conduct specified due diligence activities and file with the SEC a report disclosing, among
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
We currently lease corporate offices at 6225 Neil Road, Reno, Nevada 89511-1136. We also occupy an approximately 807,000 square foot office and manufacturing facility located in the Industrial Park of Yavne, Israel, which we lease from the Israel Land Administration. See Item 13 — “Certain Relationships and Related Transactions”. We also lease small offices in each of the countries in which we operate.
We are planning to move from our current corporate offices to larger offices during the second quarter of 2018. We believe that our current manufacturing facilities will be adequate for our operations as currently
Each of our power plants is located on property leased or owned by us or one of our subsidiaries, or is a property that is subject to a concession agreement.
Information and descriptions of our plants and properties are included in Item 1 — “Business”, of this annual report.
There were no material developments in any legal proceedings to which the Company was a party during fiscal year
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
Our common stock
As of
Dividends
We have adopted a dividend policy pursuant to which we currently expect to distribute at least 20% of our annual profits available for distribution by way of quarterly dividends. In determining whether there are profits available for distribution, our Board
Notwithstanding this policy, dividends will be paid only when, as and if approved by our Board
We have declared the following dividends over the past two years:
High/Low Stock Prices
The following table sets forth the high and low sales prices of our common stock for the years ended December 31,
Stock Performance Graph
The following performance graph represents the cumulative total shareholder return for the period November 11, 2004 (the date upon which trading of the Company’s common stock commenced) through December 31,
Comparison of Cumulative Returns for the Period November 11, 2004 through December 31,
* IPP Peers are The AES Corporation, NRG Energy Inc., Calpine Corporation and Covanta Holding Corp. ** Renewable Energy (Renewable) Peers are Acciona S.A. and U.S. Geothermal Inc.
The above Stock Performance Graph shall not be deemed to be soliciting material or to be filed with the SEC under the Securities Act and the Exchange Act except to the extent that the Company specifically requests that such information be treated as soliciting material or specifically incorporates it by reference into a filing under the Securities Act or the Exchange Act.
Equity Compensation Plan Information
For information on our equity compensation plan, refer to Item 12 — “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters”.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth our selected consolidated financial data for the years ended and at the dates indicated. We have derived the selected consolidated financial data for the years ended December 31, 2017, 2016
The information set forth below should be read in conjunction with Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements, including the notes thereto, set forth in Item 8 of this annual report.
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 2017 Revenues
For the year ended December 31,
For the year ended December 31,
During the years ended December 31,
For the year ended December 31,
For the year ended December 31,
Historically, we have entered into derivatives transactions to reduce our economic exposure to fluctuations in the price of natural gas and oil. We recently
Revenues attributable to our Electricity segment
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
Our management assesses the performance of our two 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.
Trends and Uncertainties
Trends, factors and uncertainties may impact our operations and financial condition, including many that we do not or cannot
This means, among other things, thatthe average price per MWh, which is one of the metrics some investors may use to evaluate power plant revenues,
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; and the construction, installation and engineering of power plant equipment.
Revenues attributable to our Electricity segment are derived from the sale of electricity from our power plants pursuant to long-term PPAs. While approximately
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 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 target capacity levels and the potential forfeiture of payments if we fail to meet certain minimum target capacity 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. The rates applicable to such payments are either fixed (subject, in certain cases, to certain adjustments) or are based on the relevant power purchaser’s avoided costs. 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,
The following table sets forth a breakdown of our revenues for the years indicated:
Geographic Breakdown of Revenues
The following table sets forth the geographic breakdown of the revenues attributable to our Electricity and Product segments for the years indicated:
The contribution of our domestic and foreign operations within our Electricity segment and Product segment to combined pre-tax income differ in a number of ways.
Electricity Segment. Our Electricity segment domestic revenues were approximately
Product Segment. Our Product segment foreign revenues were
Relative Contributions. While our combined (domestic and foreign) Electricity segment revenues exceeded our combined Product segment revenues by approximately
Seasonality
Breakdown of Cost of Revenues
Electricity Segment
The principal cost of revenues attributable to our operating power plants includes 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 and, for some of our projects, purchases of make-up water for use in our cooling towers and also depreciation and amortization. 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
Product Segment
The principal cost of revenues attributable to our Product segment includes 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.
Cash and Cash Equivalents
Our cash and cash equivalents, as of December 31,
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 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.
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 analyses, 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
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
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,
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 recently enacted 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 U.S., we may be required to reduce this valuation allowance, resulting in income tax benefits in our consolidated statement of operations.
In the ordinary course of business, there 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.
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. A comparison of the different years described below may be of limited utility due to (i) our recent construction or disposition of new power plants and enhancement of acquired power plants and (ii) fluctuation in revenues from our Product segment.
Comparison of the Year Ended December 31, 2017 and the Year Ended December 31, 2016 Total Revenues Total revenues for the year ended December 31, 2017 were $692.8 million, compared to $662.6 million for the year ended December 31, 2016, representing a 4.6% increase from the prior period. This increase was attributable to our Electricity segment, in which revenues increased by 7.3% compared to the corresponding period in 2016. Electricity Segment Revenues attributable to our Electricity segment for the year ended December 31, 2017, were $468.3 million, compared to $436.3 million for the year ended December 31, 2016, representing a 7.3% increase from the prior period. This increase was primarily attributable to: (i) the full year consolidation of our Bouillante power plant in Guadeloupe, effective July 5, 2016, with revenues of $21.7 million for the year ended December 31, 2017, compared to $8.1 million for the year ended December 31, 2016; (ii) the commencement of commercial operation of our Platanares power plant in Honduras, effective September 2017, with revenues of $10.0 million for the year ended December 31, 2017 and of our Tungsten Mountain power plant in Nevada, effective December 2017, with revenues of $2.2 million for the year ended December 31, 2017; (iii) an increase in generation at our Puna power plant attributable to successful improvement of the resource performance; and (iv) $2.7 million generated by our Viridity business from the provision of energy storage and demand response services. The increase was partially offset by a decrease in generation at some of our power plants that we had scheduled to take offline to address maintenance issues. Power generation in our power plants increased by 1.7% from 5,396,959 MWh in the year ended December 31, 2016 to 5,489,234 MWh in the year ended December 31, 2017, primarily because of an increase in generation at our Puna power plant, the consolidation of our Bouillante power plant in Guadeloupe, and the commencement of operations of our Platanares power plant in Honduras and Tungsten Mountain power plant in Nevada, partially offset by a decrease in generation in some of our power plants mainly due to scheduled outages. Product Segment Revenues attributable to our Product segment for the year ended December 31, 2017 were $224.5 million, compared to $226.3 million for the year ended December 31, 2016, representing a 0.8% decrease from the prior period. The slight decrease in our Product segment revenues was primarily attributable to completion or near-completion of our contracts for the Cerro Pabellon geothermal power plant in Chile, the Sarulla geothermal power plant in Indonesia, and other projects in Turkey, which were completed during 2016. This decrease was partially offset by revenue recognition from two new geothermal projects in New Zealand and China (on which we started construction in the first quarter of 2017) and new projects in Turkey in the amounts of $31.7 million, $23.1 million and $121.3 million, respectively. Total Cost of Revenues Total cost of revenues for the year ended December 31, 2017 was $424.4 million, compared to $391.8 million for the year ended December 31, 2016, representing a 8.3% increase from the prior period. This increase was attributable to an increase in cost of revenues from both the Electricity and Product segments. As a percentage of total revenues, our total cost of revenues for the year ended December 31, 2017 increased to 61.3%, compared to 59.1% for the year ended December 31, 2016. This increase was mainly attributable to an increase in cost of revenues as a percentage of total revenues in our Product segment. Electricity Segment Total cost of revenues attributable to our Electricity segment for the year ended December 31, 2017 was $272.3 million, compared to $261.6 million for the year ended December 31, 2016, representing a 4.1% increase from the prior period. This increase was primarily attributable to additional cost of revenues from the consolidation of our Bouillante power plant in Guadeloupe, effective July 5, 2016, the commencement of commercial operation of our Platanares power plant in Honduras, effective September 2017, as well as cost of revenues in the amount of $5.4 million related to our energy storage and demand response activity of our Viridity business. As a percentage of total Electricity segment revenues, the total cost of revenues attributable to our Electricity segment for the year ended December 31, 2017 was 58.1%, compared to 60.0% for the year ended December 31, 2016. This decrease was primarily attributable to higher efficiency in some of our operating power plants. Product Segment Total cost of revenues attributable to our Product segment for the year ended December 31, 2017 was $152.1 million, compared to $130.2 million for the year ended December 31, 2016, representing a 16.8% increase from the prior period. This increase was primarily attributable to additional costs associated with our project in Chile, as well as a different product mix and different margins in the various sales contracts we entered into for the Product segment during these periods. As a percentage of total Product segment revenues, our total cost of revenues attributable to the Product segment for the year ended December 31, 2017 was 67.8%, compared to 57.5% for the year ended December 31, 2016. Research and Development Expenses Research and development expenses for the year ended December 31, 2017 were $3.2 million, compared to $2.8 million for the year ended December 31, 2016. Selling and Marketing Expenses Selling and marketing expenses for the year ended December 31, 2017 were $15.6 million, compared to $16.4 million for the year ended December 31, 2016. This decrease was primarily due to lower sales commissions related to our Product segment because of a different commissions mix. Selling and marketing expenses for the year ended December 31, 2017 constituted 2.3% of total revenues for such year, compared to 2.5% of such revenues for the year ended December 31, 2016. General and Administrative Expenses General and administrative expenses for the year ended December 31, 2017 were $42.9 million, compared to $46.7 million for the year ended December 31, 2016. This decrease was mainly due to (i) $11.0 million of expenses in the year ended December 31, 2016 related to the settlement of a qui tam claim and (ii) a $2.1 million adjustment in respect of an earn out related to the acquisition of our Viridity business, partially offset by (i) a $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 approximately 22% of our shares of common stock; (ii) general and administrative expenses related to our Viridity business; and (iii) $2.5 million in costs associated with the ORIX transaction and other acquisitions and sales activities in the year ended December 31, 2017. General and administrative expenses for the year ended December 31, 2017, excluding the one-time charge of $2.1 million for stock-based compensation, constituted 5.9% of total revenues for the year ended December 31, 2017, compared to 5.5%, excluding the one-time charge of $11.0 million related to the settlement mentioned above, of total revenues for the year ended December 31, 2016. Write-off of Unsuccessful Exploration Activities Write-off of unsuccessful exploration activities for the year ended December 31, 2017 was $1.8 million, compared to $3.0 million for the year ended December 31, 2016. 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. The majority of the write-off of unsuccessful exploration activities for the year ended December 31, 2016 consisted of costs related to the Twilight site in Oregon and a concession in Chile, which we determined would not support commercial operations. Operating Income Operating income for the year ended December 31, 2017 was $205.0 million, compared to $201.9 million for the year ended December 31, 2016, representing a 1.6% increase from the prior period. The increase in operating income was primarily attributable to the increase in our gross margin in our Electricity segment primarily as a result of the increase in revenues and higher efficiency in some of our operating power plants, and the decrease in general and administrative expenses, as discussed above. The increase was partially offset by a decrease in our gross margin in our Product segment, also discussed above. Operating income attributable to our Electricity segment for the year ended December 31, 2017 was $154.5 million, compared to $126.8 million for the year ended December 31, 2016. Operating income attributable to our Product segment for the year ended December 31, 2017 was $50.5 million, compared to $75.1 million for the year ended December 31, 2016. Interest Expense, Net Interest expense, net, for the year ended December 31, 2017 was $54.1 million, compared to $67.4 million for the year ended December 31, 2016, representing a 19.7% decrease from the prior period. This decrease was primarily due to: (i) the repayment, in September 2016, of $250 million of our senior unsecured bonds which bore interest at a fixed rate of 7% per annum, through the issuance of $67 million and $137 million, respectively of two new series of senior unsecured bonds, which bear interest at a fixed rate of 3.7% and 4.45% per annum, respectively, as discussed below; (ii) lower interest expense as a result of principal payments of long term debt and revolving credit lines with banks; and (iii) a $3.9 million decrease related to an increase in interest capitalized to projects, partially offset by the December 2016 issuance of senior secured notes issued by our subsidiary that owns phase 1 of the Don A. Campbell power plant. Derivatives and Foreign Currency Transaction Gains (Losses) Derivatives and foreign currency transaction gains for the year ended December 31, 2017 were $2.7 million, compared to losses of $5.5 million for the year ended December 31, 2016. Derivatives and foreign currency transaction gains for the year ended December 31, 2017 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, 2016 were primarily attributable to $2.6 million in losses from future contracts entered into to reduce our economic exposure to fluctuations in prices of natural gas and oil under our SO#4 and Puna PPAs, which were not accounted for as hedge transactions, and $1.5 million in losses due to changes in the fair value of the contract obligation in relating to the acquisition of our interest in the Bouillante power plant in Guadeloupe. Income Attributable to Sale of Tax Benefits Income attributable to the sale of tax benefits to institutional equity investors (as described below under “OPC Transaction”, “ORTP Transaction” and “Opal Geo Transaction”) for the year ended December 31, 2017 was $17.9 million, compared to $16.5 million for the year ended December 31, 2016. This income primarily represents the value of PTCs and taxable income or loss generated by Opal Geo and ORTP and allocated to investors in the year ended December 31, 2017 compared to PTCs and taxable income or loss generated by ORTP and OPC and allocated to investors in the year ended December 31, 2016. Other Non-Operating Expense, Net Other non-operating expense, net for the year ended December 31, 2017 was $1.7 million, compared to $5.4 million for the year ended December 31, 2016. 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 (as described below). Other non-operating expense, net for the year ended December 31, 2016 includes: (i) prepayment fees of approximately $5.0 million due to the repayment of our senior unsecured bonds in September 2016 and (ii) a make whole premium of $0.6 million resulting from the repurchase of $6.8 million aggregate principal amount of our OFC Senior Secured Notes. 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, 2017 was $170.7 million, compared to $141.1 million for the year ended December 31, 2016, representing a 21.0% increase from the prior period. The income is primarily attributable to our foreign operations. This increase was driven by the increase in our domestic operations resulting mainly from the $11.0 million one-time expense in the year ended December 31, 2016 related to the settlement of a qui tam claim, approximately $5.0 million due to the repayment of the senior unsecured bonds in September 2016 and the associated decrease in interest expense, as described above. Income Taxes Income tax benefit for the year ended December 31, 2017, was $1.4 million, compared to an income tax provision of $31.8 million for the year ended December 31, 2016. The decrease in income tax provision from $31.8 million in the year ended December 31, 2016 to income tax benefit of $1.4 million in the year ended December 31, 2017, primarily resulted from changes in valuation allowance and the impact of the U.S. tax reform legislation. Our effective tax rate for the years ended December 31, 2017 and 2016, was (0.8)% and 22.5%, respectively. Our effective tax rate is principally based upon the composition of the income in different countries, the impact of U.S. tax reform legislation and changes related to valuation allowances for certain countries. Our aggregate effective tax rate is lower than the 35% U.S federal statutory tax rate due to: (i) as a substantial portion of our income is derived in Israel which is taxed at the corporate tax rate of 16%, partially offset by taxes on earnings in Kenya which are taxed at statutory rate of 37.5%; (ii) a tax credit and tax exemption related to the Company’s subsidiaries in Guatemala and Honduras; (iii) a partial valuation allowance release against the Company's U.S. deferred tax assets offset by withholding taxes; and (iv) impacts of U.S. tax reform legislation, specifically the remeasurement of deferred taxes and the inclusion in taxable income of the amount of certain repatriated earnings of foreign subsidiaries (see Note 18 to our consolidated financial statements set forth in Item 8 of this annual report for further details regarding the Company's income tax provision and the Tax Act). For the year ended December 31, 2017 and 2016, we recorded a valuation allowance in the amount of approximately $50.9 million and $109.6 million, respectively, against our unutilized foreign tax credits (FTCs, PTCs and ITCs) and U.S. deferred tax assets related to net operating loss (NOL) carryforwards. As of December 31, 2017, we had U.S. federal NOLs in the amount of approximately $145.0 million, state NOLs in the amount of approximately $222.2 million and unutilized tax credits of approximately $172.2 million, all of which can be carried forward for 10-20 years. The related deferred tax assets totaled approximately $133.0 million. Realization of these deferred tax assets and tax credits is dependent on generating sufficient taxable income in the U.S. 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 $50.9 million was recorded against the U.S. deferred tax assets as of December 31, 2017 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. Equity in losses of investees, net Equity in losses of investees, net in the year ended December 31, 2017 was $2.0 million, compared to $7.7 million in the year ended December 31, 2016. Equity in losses of investees, net derived from our 12.75% share in the losses of the Sarulla project and from profits elimination. Net Income Net income for the year ended December 31, 2017 was $170.2 million, compared to $101.5 million for the year ended December 31, 2016, representing an increase of $68.7 million from the prior period. This increase in net income was primarily attributable to $11.0 million in one-time general and administrative expenses in the year ended December 31, 2016 related to the settlement of a qui tam claim, a decrease in interest expense of $13.2 million and a decrease in income taxes of $33.2 million, each as discussed above.
Comparison of the Year Ended December 31, 2016 and the Year Ended December 31, 2015 Total Revenues
Total revenues for the year ended December 31, 2016 were $662.6 million compared to $594.6 million for the year ended December 31, 2015, representing a 11.4%increase from the prior period. This increase was attributable to both our Electricity and Product segments, in which revenues increased by 16.1% and 3.5%, respectively, compared to the corresponding period in 2015.
Electricity Segment Revenues attributable to our Electricity segment for the year ended December 31, 2016 were $436.3 million, compared to $375.9 million for the year ended December 31, 2015, representing a 16.1% increase from the prior period. This increase was primarily attributable to: (i) the commencement of operations of the second phase of the McGinness Hills and Don A. Campbell power plants in Nevada in February 2015 and September 2015, respectively, as well as the commencement of operations of our Plant 4 at the Olkaria III complex in Kenya in January 2016; (ii) higher energy rates under the Heber 1 PPA commencing in December 2015, and (iii) the consolidation of our Bouillante power plant in Guadeloupe, effective July 5, 2016, following the acquisition of an approximately 60% equity interest in GB. The increase was partially offset by a reduction in revenues generated by some of our power plants due to lower oil and natural gas prices.
Power generation in our power plants increased by 11.6% from 4,835,109 MWh in the year ended December 31, 2015 to 5,396,959 MWh in the year ended December 31, 2016, mainly due to commencement of commercial operation of the second phase of the McGinness Hills power plant and Don A. Campbell power plant in Nevada, and the commencement of operations of our Plant 4 at the Olkaria III complex in
Product Segment
Revenues attributable to our Product segment for the year ended December 31, 2016 were $226.3 million, compared to $218.7 million for the year ended December 31, 2015,
Total Cost of Revenues
Total cost of revenues for the year ended December 31, 2016 was $391.8 million, compared to $376.4 million for the year ended December 31, 2015, representing a 4.1% increase from the prior period. As a percentage of total revenues, our total cost of revenues for the year ended December 31, 2016 decreased to 59.1%, compared to 63.3% for the year ended December 31, 2015.
Electricity Segment
Total cost of revenues attributable to our Electricity segment for the year ended December 31, 2016 was $261.6 million, compared to $242.6 million for the year ended December 31, 2015, representing a 7.8% increase from the prior period. This increase was primarily due to: (i) additional cost of revenues from the second phase of the McGinness Hills and Don A. Campbell power plants, the commencement of operations of our Plant 4 at the Olkaria III complex, and the consolidation of our Bouillante power plant all discussed above; and (ii) reimbursement of $2.5 million of mining tax imposed on us based on an audit performed by the state of Nevada for the years ended December 31, 2008, 2009 and 2010 following our successful appeal of the audit decision in the first quarter of 2015. As a percentage of total Electricity segment revenues, the total cost of revenues attributable to our Electricity segment for the year ended December 31, 2016 was 60.0%, compared to 64.5% for the year ended December 31, 2015. This decrease was primarily due to higher efficiency in some of our operating power plants as well as lower costs of operating the three new power plants mentioned above.
Product Segment
Total cost of revenues attributable to our Product segment for the year ended December 31, 2016 was $130.2 million, compared to $133.8 million for the year ended December 31, 2015, representing a 2.6% decrease from the prior period. This decrease was primarily attributable to efficiencies, cost savings and project management, offset partially due to the increase 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, 2016 was 57.5%, compared to 61.2% for the year ended December 31, 2015. This decrease was mainly attributable to improvements made at our manufacturing facility and our project management and construction costs as well as the different product mix and different margins in the various sales contracts we entered into for this segment during these periods.
Research and Development Expenses
Research and development expenses for the year ended December 31, 2016 were $2.8 million, compared to $1.8 million for the year ended December 31, 2015.
Selling and Marketing Expenses
Selling and marketing expenses for the year ended December 31, 2016 were $16.4 million, compared to $16.1 million for the year ended December 31, 2015. Selling and marketing expenses for the year ended December 31, 2016 constituted 2.5% of total revenues for such year, compared to 2.7% of such revenues for the year ended December 31,
General and Administrative Expenses
General and administrative expenses for the year ended December 31, 2016 were $46.7 million, compared to $34.8 million for the year ended December 31, 2015. This increase was mainly due to $11.0 million expenses related to a settlement with certain of our former employees
Write-off of Unsuccessful Exploration Activities
Write-off of unsuccessful exploration activities for the year ended December 31, 2016 was $3.0 million compared to $1.6 million for the year ended December 31, 2015. The majority of the write-off of unsuccessful exploration activities for the year ended December 31, 2016 represented the costs related to the Twilight site in Oregon and concession in Chile, which we determined would not support commercial
Operating Income
Operating income for the year ended December 31, 2016 was $201.9 million, compared to $164.1 million for the year ended December 31, 2015, representing a 23.1% increase from the prior period. The increase in operating income was primarily attributable to the increase in our gross margin in both our Electricity and Product segments primarily due to the increase in revenues, as discussed above, partially offset by $11.0 million one-time expenses related to a settlement with certain of our former employees
Interest Expense, Net
Interest expense, net, for the year ended December 31, 2016 was $67.4 million, compared to $72.6 million for the year ended December 31, 2015, representing a 7.1% decrease from the prior period. This decrease was primarily due to: (i) the repayment, in September 2016, of the senior unsecured bonds in the amount of $250 million which bore interest at a fixed rate of 7% per annum, by issuance of new series of senior unsecured bonds in the amounts of $67 million and $137 million, respectively
Derivatives and Foreign Currency Transaction Losses
Derivatives and foreign currency transaction losses for the year ended December 31, 2016 were $5.5 million, compared to $1.6 million for the year ended December 31, 2015. Derivatives and foreign currency transaction losses for the year ended December 31, 2016 were attributable primarily to $2.6 million in losses from future contracts to reduce our economic exposure to fluctuations in prices of natural gas and oil under our SO#4 and Puna PPAs,
Income Attributable to Sale of Tax Benefits
Income attributable to the sale of tax benefits to institutional equity investors (as described below under “OPC Transaction” and “ORTP Transaction”) for the year ended December 31, 2016 was $16.5 million, compared to $25.4 million for the year ended December 31, 2015. This income represents mainly the value of PTCs and taxable income or loss generated by ORTP and allocated to investors. This decrease was primarily attributable to a lower taxable loss in ORTP.
Other non-operating income
Other non-operating loss for the year ended December 31, 2016 was $5.4 million, compared to $2.0 million in the year ended December 31, 2015. Other non-operating loss for the year ended December 31, 2016 includes: (i) prepayment fees of approximately $5.0 million due to the repayment of the senior unsecured bonds in September 2016, as discussed below; and (ii) a
Income from operations, before income taxes and equity in
Income from
Income Taxes
Income tax provision for the year ended December 31, 2016 was $31.8 million, compared to income tax benefit of $15.3 million for the year ended December 31, 2015. Income tax benefit for the year ended December 31, 2015 includes a $49.4 million deferred tax asset relating to the release of the valuation allowance for the additional 50% investment deduction for our Olkaria 3 power plant based on amendments to the Kenya Income Tax Act that came into effect on September 11, 2015 and which extended the period to utilize such investment deduction from five years to ten years. Income tax provision for the year ended December 31, 2015, excluding the $49.4 million, was $34.1 million. The increase in income tax provision from $34.1 million, excluding the $49.4 million, in the year ended December 31, 2015 to $36.5 million,
For the year ended December 31,
Equity in losses of
Equity in losses of investees, net in the year ended December 31, 2016 was $7.7 million, compared to $5.5 million in the year ended December 31, 2015. Equity in losses of investees, net derived from our 12.75% share in the losses of the Sarulla project and from profits elimination.
Net Income
Net income for the year ended December 31, 2016 was $101.5 million, compared to $123.3 million for the year ended December 31, 2015, representing a decrease of $21.8 million from the prior period. This decrease in net income was primarily attributable to $11.0 million in one-time general and administrative expenses related to the settlement paid in connection with the FCA claim, as discussed above, the $47.1 million increase in income tax provision, a decrease of $8.9 million in income attributable to sale of tax benefits, and $3.4 million increase in other non-operating loss, partially offset by an increase of $53.3 million in gross margin and a decrease in interest expense of $5.2 million, all as discussed above.
Liquidity and Capital Resources
Our principal sources of liquidity
As of December 31,
Our estimated capital needs for
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 financing and refinancing (including
. Although we plan to repatriate undistributed earnings related to Ormat Systems to support expected capital expenditure requirements in the U.S., based upon our plans to increase
Third-Party Debt
Our third-party debt
Non-Recourse and Limited-Recourse Third-Party Debt
OFC Senior Secured Notes — Non-Recourse
In February 2004,
OrCal Geothermal Senior Secured Notes — Non-Recourse
In December 2005, OrCal, one of our subsidiaries, issued $165.0 million of OrCal Senior Secured Notes for the purpose of refinancing the acquisition cost of the Heber complex. The OrCal Senior Secured Notes have been rated BBB- by Fitch Ratings. The OrCal Senior Secured Notes have a final maturity date of December 30, 2020. Principal and interest on the OrCal Senior Secured Notes are payable in semi-annual
OFC 2 Senior Secured Notes — Limited Recourse In September 2011, our subsidiary OFC 2
In October 2011, the OFC 2 Issuers completed the sale of $151.7 million aggregate principal amount of 4.687% Series A Notes due 2032 (the
On June 20, 2014, Phase I of the Tuscarora facility achieved project completion under the
On August 29, 2014, OFC 2
There were
We provided a guarantee in connection with the issuance of the Series A Notes and Series C Notes, which
Olkaria III Finance Agreement with OPIC — Limited Recourse In August 2012, OrPower 4, one of our subsidiaries, entered into a finance agreement with OPIC, an agency of the U.S. government, to provide limited-recourse senior secured debt financing in an aggregate principal amount of up to $310.0 million (the OPIC Loan) for the refinancing and financing of our Olkaria III geothermal power plant complex in Kenya. The finance agreement was amended on November 9, 2012.
The OPIC Loan is comprised of three tranches:
Tranche I in an aggregate principal amount of $85.0 million, which matures on December 15, 2030 and bears interest at a fixed rate of 6.34%, was drawn in November 2012
Tranche II in an aggregate principal amount of $180.0 million, which matures on June 15, 2030 and bears interest at a fixed rate of 6.29%, was used to fund the construction and well field drilling for Plant 2 of the Olkaria III
Tranche III in an aggregate principal amount of $45.0 million, which matures on December 15, 2030 and bears interest at a fixed rate of 6.12%, was used to fund the construction of Plant 3 of the Olkaria III
OrPower 4
The OPIC Loan is secured by substantially all of OrPower 4’s assets and by a pledge of all of the equity interests in OrPower 4.
The finance agreement includes customary events of default, including failure to pay any principal, interest or other amounts when due, failure to comply with covenants, breach of representations and warranties, non-payment or acceleration of other debt of OrPower 4, bankruptcy of OrPower 4 or certain of its affiliates, judgments rendered against OrPower 4, expropriation, change of control, and revocation or early termination of security documents or certain project-related agreements, subject to various exceptions and notice, cure and grace periods.
There are various restrictive covenants under the OPIC Loan, which include a required historical and projected 12-month DSCR of not less than 1.4 (measured as of March 15, June 15, September 15 and December 15 of each year). If OrPower 4 fails to comply with these financial ratios it will be prohibited from making distributions to its shareholders. In addition, if the DSCR falls below 1.1, subject to certain cure rights such failure will constitute an event of default by OrPower 4. This covenant in respect of Tranche I became effective on December 15, 2014. As of December 31,
As of December 31,
Amatitlan Financing — Limited Recourse
On July 31, 2015, one of our indirect wholly-owned subsidiaries, Ortitlản, Limitada, obtained a 12-year secured term loan in the principal amount of $42.0 million for the 20 MW Amatitlan power plant in Guatemala. Under the credit agreement with Banco Industrial S.A. and Westrust Bank (International) Limited, we can expand the Amatitlan power plant with financing to be provided either via equity, additional debt from Banco Industrial S.A. or from other lenders, subject to certain limitations on expansion financing in the credit agreement.
The loan is payable in 48 quarterly payments commencing September 30, 2015. The loan bears interest at a rate per annum equal to the sum of the LIBO Rate (which cannot be lower than 1.25%) plus a margin of (i) 4.35% as long as the
There are various restrictive covenants under the Amatitlan credit agreement. These include, among others, (i) a financial covenant to maintain a Debt Service Coverage Ratio (as defined in the credit agreement) of not less than 1.15 to 1.00 as of the last day of any fiscal quarter and (ii) limitations on Restricted Payments (as defined in the credit agreement) that among other things would limit dividends that could be paid to us unless the historical and projected Debt Service Coverage Ratio is not less than 1.25 to 1.00 for the four fiscal quarterly periods (calculated as a single accounting period). As of December 31,
The loan is secured by substantially all the assets of the borrower and a pledge of all of the membership interests of the borrower.
The Company has guaranteed payment of all obligations under the credit agreement and related financing documents. The guaranty is limited in the sense that the Company is only required to pay the guaranteed obligations if a “trigger event” occurs. A trigger event is the occurrence and continuation of a default by INDE in its payment obligations under the
As of December 31,
Don A. Campbell Senior Secured Notes — Non-Recourse
On November 29, 2016, ORNI 47 LLC (“ORNI 47”) entered into a note purchase agreement (the
The net proceeds to ORNI 47 from the sale of the DAC 1 Senior Secured Notes, after deducting certain transaction expenses and the funding of a debt service reserve account, were approximately
ORNI 47
The DAC 1 Senior Secured Notes constitute senior secured obligations of ORNI 47 and are secured by all of the assets of ORNI 47. Under the ORNI 47 Note Purchase Agreement, ORNI 47 may prepay at any time all, or from time to time any part of, the DAC 1 Senior Secured Notes in an amount equal to at least $2 million or such lesser amount as may remain outstanding under the DAC 1 Senior Secured Notes at 100% of the principal amount to be prepaid plus the applicable make-whole amount determined for the prepayment date with respect to such principal amount. Upon the occurrence of a Change of Control (as defined in the ORNI 47 Note Purchase Agreement), ORNI 47 must make an offer to each holder of DAC 1 Senior Secured Notes to repurchase all of the holder’s DAC 1 Senior Secured Notes at 101% of the aggregate principal amount of DAC 1 Senior Secured Notes to be repurchased plus accrued and unpaid interest, if any, on the DAC 1 Senior Secured Notes to be repurchased,
As of December 31,
Full-Recourse Third-Party Debt
Credit Agreements
Union Bank. In February 2012, Ormat Nevada, our wholly owned subsidiary, entered into an amended and restated credit agreement with Union Bank. Under the credit agreement
There are various restrictive covenants under the credit agreement, including a requirement for Ormat Nevada to comply with the following financial ratios, which are measured quarterly: (i) a 12-month debt to EBITDA ratio not to exceed 4.5; (ii) 12-month DSCR of not less than 1.35; and (iii) distribution leverage ratio not to exceed 2.0. As of December 31,
As of December 31,
HSBC. In May 2013, Ormat Nevada entered into a credit agreement with HSBC Bank USA, N.A for one year with annual renewals. The current expiration date of the credit facility
There are various restrictive covenants under the credit agreement, including a requirement to comply with the following financial ratios, which are measured quarterly: (i) a 12-month debt to EBITDA ratio not to exceed 4.5; (ii) 12-month DSCR of not less than 1.35; and (iii) distribution leverage ratio not to exceed 2.0. As of December 31,
As of December 31,
CHUBB Surety Bond. In May 2017, the Company entered into a surety bond agreement (the “Surety Agreement”) with Chubb Limited (“Chubb”) pursuant to which the Company may request that Chubb issue up to an aggregate $200.0 million of surety bonds with respect to the contractual obligations of the Company and its subsidiaries in exchange for bank letters of credit or as otherwise may be required. There is no expiration date for the Surety Agreement, but it may be terminated by the Company at any time upon twenty days’ prior written notice to Chubb. Delivery of such termination notice will not affect any surety bonds issued and outstanding prior to the date on which such notice is delivered. As of December 31, 2017, Chubb issued a surety bond in the amount of $106.2 million under the Surety Agreement, primarily in in respect of the Company’s obligations under the PPA with SCPPA. Other Banks. We also have committed credit agreements with five other commercial banks for an aggregate amount of
As of December 31,
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.
As of December 31,
Term Loans. We
Senior Unsecured Bonds. We
The Series 2 Bonds will mature in September 2020 and bear interest at a fixed rate of 3.7% per annum, payable semi-annually. The Series 3 Bonds will mature in September 2022 and bear interest at a fixed rate of 4.45% per annum, payable semi-annually. The Series 2 Bonds and Series 3 Bonds will be repaid at maturity in a single bullet payment, unless earlier prepaid
Loan Agreements with DEG
On October 20, 2016, OrPower 4 entered into a new $50 million subordinated Under the DEG 2
As of December 31,
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,
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 (or Ormat Systems’) full-recourse bank credit agreements will not materially impact our business plan or operations.
Future minimum payments
Future minimum payments under long-term obligations, excluding revolving credit lines with commercial banks and lease payments under the Puna lease transaction described below, as of December 31,
Puna Power Plant Lease Transactions
In May 2005, our Hawaiian subsidiary, PGV, entered into a transaction involving the original geothermal power plant of the Puna complex located on the Big Island (the Puna Power Plant).
Pursuant to a 31-year head lease (the Head Lease), PGV leased the Puna Power Plant to an unrelated lessor (the Puna lessor) in return for prepaid lease payments in the total amount of $83.0 million. The carrying value of the leased assets as of
The transaction was concluded with financing parties by means of a leveraged lease transaction. A secondary stage of the lease transaction relating to two new geothermal wells that PGV drilled in the second half of 2005 (for production and injection) was completed on December 30, 2005. Pursuant to a 31-year head lease, PGV leased its geothermal power plant to the abovementioned financing parties in return for payments of $83.0 million by such financing parties to PGV, which are accounted for as deferred lease income.
There are various restrictive covenants under the lease agreement, including a requirement to have certain reserve funds that need to be managed by the indenture trustee in accordance with certain balance requirements. Such reserve funds amounted to
Opal Geo Transaction
On December
In connection with the transactions contemplated by the Equity Contribution Agreement and the LLC Agreement, Ormat Nevada transferred its indirect ownership interest in the McGinness Hills (Phase I and Phase II), Tuscarora, Jersey Valley and phase 2 of the Don A. Campbell
Pursuant to the Equity Contribution Agreement, JPM contributed approximately $62.1 million to Opal Geo in exchange for 100% of the Class B Membership Interests of Opal Geo. JPM also agreed to make deferred capital contributions to Opal Geo based on the amount of electricity generated by the DAC 2 and McGinness Hills Phase II power plants which are eligible for the federal
Under the LLC Agreement, until December 31, 2022, OrLeaf will receive distributions of 97.5% of any distributable cash generated by operation of the power plants while JPM will receive distributions of 2.5% of any distributable cash generated by operation of the power plants. Unless JPM has already achieved its target internal rate of return on its investment in Opal Geo, from December 31, 2022 until JPM has achieved its target internal rate of return, JPM will receive 100% of any distributable cash generated by operation of the power plants. Thereafter, OrLeaf will receive distributions of 97.5%, and JPM will receive 2.5%, of any distributable cash generated by operation of the power plants.
Under the LLC Agreement, all items of Opal Geo income and loss, gain, deduction and credit (including the federal PTCs relating to the operation of the two PTC eligible power plants) will be allocated, until JPM has achieved its target internal rate of return on its investment in Opal Geo (and for so long as the two PTC eligible power plants are generating PTCs), 99% to JPM and 1% to OrLeaf, or 5% to JPM and 95% to OrLeaf if PTCs are no longer available to either of the two PTC eligible power plants. Once JPM achieves its target internal rate of return, all items of Opal Geo income and loss, gain, deduction and credit will be allocated 5% to JPM and 95% to OrLeaf.
Under the LLC Agreement, OrLeaf, which owns 100% of the Class A Membership Interests in Opal Geo, will serve as the managing member of Opal Geo and control the day-to-day management of Opal Geo and its portfolio of five power plants. However, in certain limited circumstances (such as bankruptcy of Orleaf, fraud or gross negligence by OrLeaf) JPM may remove OrLeaf as the managing member of Opal Geo. JPM, as the Class B Member of Opal Geo, has consent and approval rights with respect to certain items that are designated as major decisions for Opal Geo and the five power plants. In addition, by virtue of certain provisions in OrLeaf’s own limited liability company agreement, and consistent with the ORPD
The LLC Agreement contains certain customary restrictions on transfer applicable to both OrLeaf and JPM with respect to their respective
Pursuant to the Equity Contribution Agreement, the Company has provided a guaranty for the benefit of JPM of certain of OrLeaf’s indemnification obligations to JPM under the LLC Agreement. In addition, Ormat Nevada also provided a guaranty for the benefit of JPM of all present and future payment and performance obligations of OrLeaf under the LLC Agreement and each ancillary document to which OrLeaf is a party.
OPC Transaction
In June 2007, Ormat Nevada entered into agreements with affiliates of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc. (Morgan Stanley Geothermal LLC and Lehman-OPC LLC, respectively), under which those investors purchased, for cash, interests in a newly formed subsidiary of Ormat Nevada, OPC, entitling the investors to certain tax benefits (such as PTCs and accelerated depreciation) and distributable cash associated with four geothermal power plants in Nevada.
The first closing under the agreements occurred in 2007 and covered our Desert Peak 2, Steamboat Hills, and Galena 2 power plants. The investors paid $71.8 million at the first closing. The second closing under the agreements occurred in 2008 and covered the Galena 3 power plant. The investors paid $63.0 million at the second closing.
Ormat Nevada
The Class B membership units have a 5% residual
ORTP Transaction
On January 24, 2013, Ormat Nevada entered into agreements with JPM under which JPM purchased interests in a newly formed subsidiary of Ormat Nevada, ORTP, entitling JPM to certain tax benefits (such as PTCs and accelerated depreciation) associated with certain geothermal power plants in California and Nevada.
Under the terms of the transaction, Ormat Nevada transferred the Heber complex, the Mammoth complex, the Ormesa complex, and the Steamboat 2 and 3, Burdette (Galena 1) and Brady power plants to ORTP, and sold Class B membership units in ORTP to JPM. In connection with the closing, JPM paid approximately $35.7 million to Ormat Nevada and
Ormat Nevada
The Class B membership units entitled the holder to a 5.0% (allocation of income and loss) and 2.5% (allocation of cash) residual economic interest in ORTP. The 5.0% and 2.5% residual interest commences on achievement by JPM of a contractually stipulated return that triggers the ORTP Flip Date, which occurred on
Liquidity Impact of Uncertain Tax Positions
As discussed in Note 19 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
Dividend
The following are the dividends declared by us during the past two years:
Historical Cash Flows
The following table sets forth the components of our cash flows for the relevant periods indicated:
For the Year Ended December 31, 2017 Net cash provided by operating activities for the year ended December 31, 2017 was $245.6 million, compared to $159.3 million for the year ended December 31, 2016. This increase of $86.3 million resulted primarily from (i) an increase in receivables of $24.0 million in the year ended December 31, 2017, compared to $33.3 million in the year ended December 31, 2016, as a result of timing of collections from our customers; and (ii) a decrease in billing in excess of costs and estimated earnings on uncompleted contracts, net of $0.1 million in our Product segment in the year ended December 31, 2017, compared to $29.3 million in the year ended December 31, 2016, as a result of timing in billing of our customers; and (iii) an increase in accounts payable and accrued expenses of $51.6 million in the year ended December 31, 2017, compared to a decrease of $1.4 million in the year ended December 31, 2016, as a result of timing of payments to our suppliers. Net cash used in investing activities for the year ended December 31, 2017 was $368.1 million, compared to $158.5 million for the year ended December 31, 2016. The principal factors that affected our net cash used in investing activities during the year ended December 31, 2017 were: (i) capital expenditures of $259.2 million, primarily for our facilities under construction; (ii) $35.3 million net cash paid for the acquisition of our Viridity business; (iii) a net increase of $14.6 million in restricted cash and cash equivalents, due to timing of debt repayments; and (iv) an investment in an unconsolidated company of $46.3 million. Net cash used in financing activities for the year ended December 31, 2017 was $59.9 million, compared to $43.5 million provided by for the year ended December 31, 2016. The principal factors that affected the net cash used in financing activities during the year ended December 31, 2017 were: (i) the repayment of long-term debt in the amount of $66.2 million; (ii) a $20.5 million cash dividend paid; (iii) $21.3 million of cash paid to noncontrolling interests; (iv) $14.3 million of cash paid to repurchase our OFC Senior Secured Notes, partially offset by a net increase of $51.5 million against our revolving lines of credit with commercial banks.
For the Year Ended December 31, 2016 Net cash provided by operating activities for the year ended December 31, 2016 was $159.3 million, compared to $190.0 million for the year ended December 31, 2015. This decrease of $30.7 million resulted primarily from (i) an increase in receivables of $33.3 million in the year ended December 31, 2016, compared to
Net cash used in investing activities for the year ended December 31, 2016 was $158.5 million, compared to $91.0 million for the year ended December 31, 2015. The principal factors that affected our net cash used in investing activities during the year ended December 31, 2016 were capital expenditures of $151.9 million, primarily for our facilities under construction, and $20.1 million net cash paid for the acquisition of GB, reduced by a net decrease of $15.2 million in restricted cash and cash equivalents, due to timing of debt repayments.
Net cash provided by financing activities for the year ended December 31, 2016 was $43.5 million, compared to $46.6 million used for the year ended December 31, 2015. The principal factors that affected the net cash provided by financing activities during the year ended December 31, 2016 were: (i) $203.5 million net proceeds from issuance of two new series of Senior Unsecured Bonds; (ii) net proceeds from issuance of shares to a noncontrolling interest in the amount of $44.1 million; (iii) $59.9 million of net proceed from the
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
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,
The following table reconciles net cash provided by operating activities to EBITDA and adjusted EBITDA, for the years ended December 31, 2017, 2016,
EBITDA includes the proportionate share (12.75%) of net depreciation, interest and tax expenses from our unconsolidated investment in the Sarulla project 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, 2017, the credit facility has an outstanding balance of $1,042.7 million. Our proportionate share in SOL credit facility is $132.9 million.
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
In addition, we estimate approximately
In the aggregate, we estimate our total capital expenditures for
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.
Exposure to Market Risks
We, like other power plant operators, are exposed to electricity price volatility
As of December 31,
We currently maintain our surplus cash in short-term, interest-bearing bank deposits, money market securities and commercial paper
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. 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
We performed a sensitivity analysis on the fair values of our
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,
(1) The application of a 10% increase
Effect of Inflation
We do not expect that inflation will 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,
Contractual Obligations and Commercial Commitments
The following tables set forth our material contractual obligations as of December 31,
___________
The table above does not reflect unrecognized tax benefits of
Concentration of Credit Risk
Our credit risk is currently concentrated with the following major customers: Southern California Edison, Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy), KPLC,
Southern California Edison accounted for
Sierra Pacific Power Company and Nevada Power Company accounted for
KPLC accounted for
SCPPA accounted for
Hyundai (Sarulla geothermal power project) accounted for
We have historically been able to collect on substantially all of our receivable balances. Recently, we have been receiving late payments from KPLC in Kenya related to our Olkaria Complex and from ENNE in Honduras related to our Platanares power plant. As we believe we will be able to collect all past due amounts, no provision for doubtful accounts has been recorded.
Tax Benefits
The New solar projects that are under construction by December 2019 will qualify for a
We are also permitted to depreciate, or write off, most of the cost of the plant. In cases where we claim the one-time 30% (or 10%) tax credit, our tax basis in the plant that we can recover through depreciation is reduced by one-half of the tax credit. In cases where we claim the production tax credit, there is no reduction in the tax basis for depreciation. Projects that are placed in service in 2016 and 2017 are eligible for “bonus” depreciation and we will be permitted to write off 50% of the cost of that equipment in the year the power plant is placed in service. Projects placed in service in 2018 would qualify for a 40% bonus and Projects placed in service in 2019 would qualify for a 30% bonus. After applying any depreciation bonus that is available, we can write off the remainder of our tax basis in the plant, if any, 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. The Tax Act, as further discussed in the MD&A section allows full expensing for certain assets acquired and placed in service after September 27, 2017. The Company will continue to analyze this new provision under the Act and determine if an election is appropriate as it relates to their 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.
Ormat Systems tax assessment for fiscal years 2010-2014 was finalized and settled in January 2017. The settlement resulted in no impact to income statement due to release of the related uncertain tax position liability.
As previously reported by the Company, the Kenya Revenue Authority (“KRA”) conducted an audit related to the Company’s operations in Kenya for fiscal years 2012 - 2013. In January 2017, KRA concluded its audit for the subject period and issued a demand letter to the Company for additional tax payments of approximately $16.1 million, including interest and penalties. KRA’s assessment, among other points, rejected the Company's income tax deduction of 150% of its investment in geothermal well drilling during the relevant period, on the basis that such work falls under mining activities (and not geothermal activities) which have a different allowable deduction under the Kenya Income Tax Act. The KRA audit and assessment is not final and is subject to objection by the Company. The Company's operations in Kenya utilize a geothermal resource license from the Ministry of Energy and Petroleum. The Company does not conduct and is not involved in any mining activity under applicable Kenyan law. Therefore, the Company believes that its original tax position was and remains correct under Kenyan tax law and regulations, and has submitted a notice of objection to the KRA which it intends to pursue vigorously. If the KRA position prevails and is applied to subsequent periods, the Company's deferred tax asset of $49.4 million recorded in 2015 may be impacted. At present, the Company has recorded a provision based on its assessment of its reasonably expected potential exposure.
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.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Ormat Technologies, Inc.:
We have audited the accompanying consolidated balance sheets of Ormat Technologies, Inc. and its subsidiaries as of December 31, 2017 and 2016, and the related consolidated statements of operations and comprehensive income (loss), of equity and of cash flows for each of the three years in the period ended December 31, 2017, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Basis for Opinions The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in We conducted our audits in accordance with the standards of the Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
/s/ PricewaterhouseCoopers LLP
San Francisco, California March We have served as the Company’s auditor since 1988.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 — BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
Business
Ormat Technologies, Inc. (the “Company”) is primarily engaged in the geothermal and recovered energy business, including the supply of equipment that is manufactured by the Company and the design and construction of power plants for projects owned by the Company or for third parties. The Company owns and operates geothermal and recovered energy-based power plants in various countries, including the United States of America (“U.S.”), Kenya, Guatemala, Guadeloupe and
Most of the Company’s domestic power plant facilities are Qualifying Facilities under the Public Utility Regulatory Policies Act of 1978 (“PURPA”). The power purchase agreements (“PPAs”) for certain of such facilities are dependent upon their maintaining Qualifying Facility status. Management believes that all of the facilities located in the U.S. were in compliance with Qualifying Facility status requirements as of December 31,
Cash dividends
During the years ended December 31, 2017,2016,
Rounding
Dollar amounts, except per share data, in the notes to these financial statements are rounded to the closest
Basis of presentation
The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and include the accounts of the Company and of all majority-owned subsidiaries in which the Company exercises control over operating and financial policies, and variable interest entities in which the Company has an interest and is the primary beneficiary. Intercompany accounts and transactions have been eliminated in consolidation.
Investments in less-than-majority-owned entities or other entities in which the Company exercises significant influence over operating and financial policies are accounted for using the equity method of accounting or consolidated if they are a variable interest entity in which the Company has an interest and is the primary beneficiary. Under the equity method, original investments are recorded at cost and adjusted by the Company’s share of undistributed earnings or losses of such companies. The Company’s earnings or losses in investments accounted for under the equity method have been reflected as “equity in
Cash and cash equivalents
The Company considers all highly liquid instruments, with an original maturity of three months or less, to be cash equivalents.
Restricted cash, cash equivalents, and marketable securities
Under the terms of certain long-term debt agreements, the Company is required to maintain certain debt service reserves, cash collateral and operating fund accounts that have been classified as restricted cash and cash equivalents. Funds that will be used to satisfy obligations due during the next twelve months are classified as current restricted cash and cash equivalents, with the remainder classified as non-current restricted cash and cash equivalents. Such amounts were invested primarily in money market accounts and commercial paper with a minimum investment grade of “AA”.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Concentration of credit risk
Financial instruments which potentially subject the Company to concentration of credit risk consist principally of temporary cash investments and accounts receivable.
The Company places its temporary cash investments with high credit quality financial institutions located in the U.S. and in foreign countries. At December 31,
At December 31,
The Company has historically been able to collect on substantially all of its receivable balances, and
Inventories
Inventories consist primarily of raw material parts and sub-assemblies for power units, and are stated at the lower of cost or
Deposits and other
Deposits and other consist primarily of performance bonds for construction projects, long-term insurance contract and receivables, and derivative instruments.
Deferred charges
Deferred charges represent prepaid income taxes on intercompany sales. Such amounts are amortized using the straight-line method and included in income tax provision over the life of the related property, plant and equipment. The Company has not elected to adopt Accounting Standards Update 2016-16, Income Taxes on Intercompany Transfers early. For additional information on the new accounting standard related to tax effects associated with intercompany transfers of assets please see "New accounting pronouncements effective in future periods" in Note 1 to our consolidated financial statements set forth in Item 8 of this annual report.
Property, plant and equipment, net
Property, plant and equipment are stated at cost. All costs associated with the acquisition, development and construction of power plants operated by the Company are capitalized. Major improvements are capitalized and repairs and maintenance (including major maintenance) costs are expensed. Power plants operated by the Company, which include geothermal wells and exploration and resource development costs, are depreciated using the straight-line method over their estimated useful lives, which range from 15 to 30 years. The other assets are depreciated using the straight-line method over the following estimated useful lives of the assets:
The cost and accumulated depreciation of items sold or retired are removed from the accounts. Any resulting gain or loss recognized currently and is recorded in the accompanying statements of operations.
The Company capitalizes interest costs as part of constructing power plant facilities. Such capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life. Capitalized interest costs amounted to
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Exploration and development costs
The Company capitalizes costs incurred in connection with the exploration and development of geothermal resources once it acquires land rights to the potential geothermal resource. Prior to acquiring land rights, the Company makes an initial assessment that an economically feasible geothermal reservoir is probable on that land. The Company determines the economic feasibility of potential geothermal resources internally, with all available data and external assessments vetted through the exploration department and occasionally using outside service providers. Costs associated with the initial assessment are expensed and included in cost of electricity revenues in the consolidated statements of operations and comprehensive income (loss). Such costs were immaterial during the years ended December 31, 2017, 2016,
In most cases, the Company obtains the right to conduct the geothermal development and operations on land owned by the Bureau of Land Management (“BLM”), various states or with private parties. In consideration for certain of these leases, the Company may pay an up-front bonus payment which is a component of the competitive lease process. The up-front bonus payments and other related costs, such as legal fees, are capitalized and included in construction-in-process. The annual land lease payments made during the exploration, development and construction phase are expensed as incurred and included in “electricity cost of revenues” in the consolidated statements of operations and comprehensive income (loss). Upon commencement of power generation on the leased land, the Company begins to pay to the lessors long-term royalty payments based on the utilization of the geothermal resources as defined in the respective agreements. Such payments are expensed when the related revenues are earned and included in “electricity cost of revenues” in the consolidated statements of operations and comprehensive income (loss).
Following the acquisition of land rights to the potential geothermal resource, the Company conducts further studies and surveys, including water and soil analyses among others, and augments its database with the results of these studies. The Company then initiates a suite of geophysical surveys to assess the resource and determine drilling locations. If the results of these activities support the initial assessment of the feasibility of the geothermal resource, the Company then proceeds to exploratory drilling and other related activities which may include drilling of temperature gradient holes, drilling of slim holes, building access roads to drilling locations, drilling full size production and/or injection wells and flow tests. If the slim hole supports a conclusion that the geothermal resource will support a commercially viable power plant, it may be converted to a full-size commercial well, used either for extraction or re-injection or geothermal fluids, or be used as an observation well to monitor and define the geothermal resource. Costs associated with these activities and other directly attributable costs, including interest once physical exploration activities begin and permitting costs are capitalized and included in “construction-in-process”. If the Company concludes that a geothermal resource will not support commercial operations, capitalized costs are expensed in the period such determination is made.
When deciding whether to continue holding lease rights and/or to pursue exploration activity, we diligently prioritize our prospective investments, taking into account resource and probability assessments in order to make informed decisions about whether a particular project will support commercial
Grants received from the U.S. Department of Energy (“DOE”) are offset against the related exploration and development costs. Such grants amounted to
All exploration and development costs that are being capitalized, including the up-front bonus payments made to secure land leases, will be depreciated over their estimated useful lives when the related geothermal power plant is substantially complete and ready for use. A geothermal power plant is substantially complete and ready for use when electricity generation commences.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Asset retirement obligation
The Company records the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. The Company’s legal liabilities include plugging wells and post-closure costs of power producing sites. When a new liability for asset retirement obligations is recorded, the Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The 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, the obligation is settled for its recorded amount at a gain or loss.
Deferred financing and lease transaction costs
Deferred financing costs are amortized over the term of the related obligation using the effective interest method. Amortization of deferred financing costs is presented as interest expense in the consolidated statements of operations and comprehensive income (loss). Accumulated amortization related to deferred financing costs amounted to $
Deferred transaction costs relating to the Puna operating lease (see Note
Goodwill
Goodwill represents the excess of the fair value of consideration transferred in the Intangible assets
Intangible assets consist of allocated acquisition costs of PPAs, which are amortized using the straight-line method over the 13 to ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Impairment of long-lived assets and long-lived assets to be disposed of
The Company evaluates 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 the Company’s use of assets or its 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 its business or when it concludes that it is more likely than not that an asset will be disposed of or sold.
The Company tests its operating plants that are operated together as a complex for impairment at the complex level because the cash flows of such plants result from significant shared operating activities. For example, the operating power plants in a complex are managed under a combined operation management generally with one central control room that controls all of the power plants in a complex and one maintenance group that services all of the power plants in a complex. As a result, the cash flows from individual plants within a complex are not largely independent of the cash flows of other plants within the complex. The Company tests for impairment its operating plants which are not operated as a complex as well as its 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, the Company 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 the Company uses in estimating its undiscounted future cash flows include: (i) projected generating capacity of the complex or power plant and rates to be received under the respective PPA(s) and expected market rates thereafter and (ii) projected operating expenses of the relevant complex or 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 the assets are considered to be impaired, the impairment to be recognized is measured by 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. Management believes that no impairment exists for long-lived assets; however, estimates as to the recoverability of such assets may change based on revised circumstances. If actual cash flows differ significantly from the Company’s current estimates, a material impairment charge may be required in the future.
Derivative instruments
Derivative instruments (including certain derivative instruments embedded in other contracts) are measured at their fair value and recorded as either assets or liabilities unless exempted from derivative treatment as a normal purchase and sale. All changes in the fair value of derivatives are recognized in earnings unless specific hedge criteria are met, which requires a company to formally document, designate and assess the effectiveness of transactions that receive hedge accounting.
The Company maintains a risk management strategy that incorporates the use of swap contracts and put options on oil and natural gas prices, forward exchange contracts, interest rate swaps, and interest rate caps to minimize significant fluctuation in cash flows and/or earnings that are caused by oil and natural gas prices, exchange rate or interest rate volatility. Gains or losses on contracts that initially qualify for cash flow hedge accounting, net of related taxes, are included as a component of other comprehensive income or loss and accumulated other comprehensive income or loss are subsequently reclassified into earnings when the hedged forecasted transaction affects earnings. Gains or losses on contracts that are not designated as a cash flow hedge are included currently in earnings.
Foreign currency translation
The U.S. dollar is the functional currency for all of the Company’s consolidated operations and those of its equity affiliates except for the Guadeloupe power plant. For those entities, all gains and losses from currency translations are included within the line item “Derivatives and foreign currency transaction gains (losses)” within the consolidated statements of operations and comprehensive income (loss). The Euro is the functional currency of the Guadeloupe power plant and thus gains and losses from currency translation adjustments related to Guadeloupe are included as currency translation adjustments in accumulated other comprehensive income in the consolidated statements of equity and in comprehensive income. The accumulated currency translation adjustments amounted to $1.4 million and $1.2 million as of December 31, 2017 and 2016, respectively. ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Comprehensive income (loss) reporting
Comprehensive income (loss) includes net income or loss plus other comprehensive income (loss), which for the Company consists of changes in unrealized gains or losses in respect of the Company’s share in derivatives instruments of unconsolidated investment, foreign currency translation adjustments and
Revenues and cost of revenues
Revenues are primarily related to: (i) sale of electricity from geothermal and recovered energy-based power plants owned and operated by the Company and (ii) geothermal and recovered energy-based power plant equipment engineering, sale, construction and installation, and operating services.
Revenues related to the sale of electricity from geothermal and recovered energy-based power plants and capacity payments are recorded based upon output delivered and capacity provided at rates specified under relevant contract terms. For PPAs agreed to, modified, or acquired in business combinations on or after July 1, 2003, the Company determines whether such PPAs contain a lease element requiring lease accounting. Revenue from such PPAs are accounted for in electricity revenues. The lease element of the PPAs is also assessed in accordance with the revenue arrangements with multiple deliverables guidance, which requires that revenues be allocated to the separate earnings processes based on their relative fair value. PPAs with minimum lease rentals which vary over time are generally recognized on the straight-line basis over the term of the PPAs. PPAs with contingent rentals are recognized when earned. In the electricity segment, revenues for all but two power plants are accounted for under ASC 840 (Leases) as operating leases, and therefore equipment related to geothermal and recovered energy generation power plants as described in Note 8 is considered held for leasing.
Revenues from engineering, operating services, and parts and product sales are recorded upon providing the service or delivery of the products and parts and when collectability is reasonably assured. Revenues from the supply and/or construction of geothermal and recovered energy-based power plant equipment and other equipment to third parties are recognized using the percentage-of-completion method. Revenue is recognized based on the percentage relationship that incurred costs bear to total estimated costs. Costs include direct material, labor, and indirect costs. Selling, marketing, general, and administrative costs are charged to expense as incurred. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Changes in job performance, job conditions, and estimated profitability, including those arising from contract penalty provisions and final contract settlements, may result in revisions to costs and revenues and are recognized in the period in which the revisions are determined.
In specific instances where there is a lack of dependable estimates or inherent risks cause forecast to be doubtful, then the completed-contract method is followed. Revenue is recognized when the contract is substantially complete and when collectability is reasonably assured. Costs that are closely associated with the project are deferred as contract costs and recognized similarly to the associated revenues.
Warranty on products sold
The Company generally provides a
Research and development
Research and development costs incurred by the Company for the development of existing and new geothermal, recovered energy and remote power technologies are expensed as incurred. Grants received from the DOE are offset against the related research and development expenses.
Stock-based compensation
The Company accounts for stock-based compensation using the fair value method whereby compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the requisite employee service period (generally the vesting period of the grant). Prior to 2016, the Company used the Black-Scholes formula to estimate the fair value of the stock-based compensation.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Tax monetization Transactions
The Company
Income taxes
Income taxes are accounted for using the asset and liability approach, which requires the recognition of taxes payable or refundable for the current year and deferred tax assets and liabilities for the future tax consequences of events that have been recognized in the Company’s financial statements or tax returns. The measurement of current and deferred tax assets and liabilities are based on provisions of the enacted tax law. On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”). The
Earnings (loss) per share
Basic earnings (loss) per share attributable to the Company’s stockholders (“earnings (loss) per share”) is computed by dividing net income or loss attributable to the Company’s stockholders by the weighted average number of shares of common stock outstanding for the period. The Company does not have any equity instruments that are dilutive, except for stock-based awards.
The table below shows the reconciliation of the number of shares used in the computation of basic and diluted earnings per share:
The number of stock-based awards that could potentially dilute future earnings per share and were not included in the computation of diluted earnings per share because to do so would have been anti-dilutive was 42,896,102,793,
Use of estimates in preparation of financial statements
The preparation of financial statements in conformity with
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
New Accounting Pronouncements
New accounting pronouncements effective in the year ended December 31,
In Interests Held through Related Parties that are under Common Control In October 2016, the Simplifying the Measurement of Inventory In July 2015, the FASB issued ASU 2015-11, Simplifying the Measurement of Inventory, Topic 330. The update contains no amendments to disclosure requirements, but replaces the concept of ‘lower of cost or market’ with that of ‘lower of cost and New accounting pronouncements effective in future periods
In
Intangibles –Goodwill and Other In
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In May 2017, the FASB issued ASU 2017-09, Compensation—Stock Compensation (Topic 718). The amendments in this Update provide guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting Business Combinations In January 2017, the FASB issued ASU Statement of Cash In November 2016, the FASB issued ASU Intra-Entity Transfers of Assets Other than Inventory
In October 2016, the FASB issued ASU
In
Revenues from Contracts with Customers In May 2014, the FASB issued ASU
In March 2016, the FASB issued ASU ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS To date, we have made substantial progress in our assessment of the impact of adopting this new guidance, and we have taken steps towards implementation. We have utilized internal resources to lead the implementation efforts and supplemented them with external resources. Our approach to implementation has consisted of (1) performing a bottom-up analysis of the impact of the standard on our portfolio of contracts, (2) reviewing our current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to our existing revenue contracts, (3) meeting with key stakeholders across the organization to discuss the impact of the standard on our existing contracts, and (4) participating in professional trainings as well as consulting with other accounting professionals to assist with the interpretation of the amended guidance. The Company has substantially completed its preliminary assessment of the potential impact that the implementation of this updated standard will have on its consolidated financial statements and continues to finalize its efforts relative to the adoption of this standard which is effective for the Company at January 1, 2018. While our current evaluation and conclusions are subject to change as our assessment continues to progress, the Company expects material impacts to the content and structure of our financial statements in the form of enhanced disclosures. Additionally, the Company expects the adoption of this standard to have an immaterial impact on its Electricity segment revenue recognition policies, as it accounts for the majority of its PPA’s under ASC 840, Leases, as well as an immaterial impact on its Product segment revenue recognition policies. The Company also reviewed the potential impact of the adoption of this standard on its investment in an unconsolidated company and concluded that the impact is expected to amount to approximately $24.1 million at January 1, 2018. This impact is a result of the unconsolidated company’s variable consideration related to the construction of its power plant for which, under the new guidance, is probable that a significant reversal in the amount of cumulative revenue recognized will not occur when the uncertainty resolved. As a result of the expected impact as aforementioned, the Company concluded that it would adopt the new standard using the modified retrospective approach with one-time cumulative adjustment to the opening balance of retained earnings of approximately $24.1 million at January 1, 2018, the date of initial application. As such, the comparative information will not be restated and shall continue to be reported under the accounting standards in effect for those periods. Leases In February 2016, the FASB issued ASU 2016-02, Leases, Topic 842. This update introduces a number of changes and simplifies previous guidance, primarily the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. The Update retains the distinction between finance leases and operating leases and the classification criteria between the two types remains substantially similar. Also, lessor accounting remains largely unchanged from previous guidance. However, key aspects of the Update were aligned with the revenue recognition guidance in Topic 606. Additionally, the Update defines a lease as a contract, or part of a contract, that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Control over the use of the identified asset means that the customer has both (a) the right to obtain substantially all of the economic benefits from the use of the asset and (b) the right to direct the use of the asset. This update requires the modified retrospective transition approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. The modified retrospective approach includes a number of optional practical expedients related to identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commenced before the effective date in accordance with the previous GAAP unless the lease is modified, except that lessees are required to recognize a right-of-use asset and a lease liability for all operating leases at each reporting date based on the present value of the remaining minimum rental payments that were tracked and disclosed under previous GAAP. The amendments in this update are effective for annual reporting periods beginning after December 15, 2018, including interim periods within those reporting periods. Early adoption is
In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities. The update primarily requires that an entity present separately, in other comprehensive income, the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk if the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. The application of this update should be by means of cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted as of the beginning of the fiscal year of adoption. The Company is currently evaluating the potential impact, if any, of the adoption of this update on its consolidated financial statements, however, such impact, if any, .
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2 —
On July 26, 2017, the Company announced that ORIX Corporation (“ORIX”) closed its acquisition of approximately 11 million shares of the Company’s common stock, representing an approximately 22% ownership stake in the Company, from FIMI ENRG Limited Partnership, FIMI ENRG, L.P., Bronicki Investments, Ltd. and certain senior members of the Company’s management team pursuant to a stock purchase agreement entered into by ORIX and the selling stockholders on May 4, 2017. In connection with the acquisition, on May 4, 2017, the Company entered into certain related agreements with ORIX, including a Governance Agreement, a Commercial Cooperation Agreement and a Registration Rights Agreement, following the unanimous recommendation of a special committee of the Board that was formed to evaluate and negotiate the stockholder arrangements proposed by ORIX, and following approval by the full Board. The closing of the transactions contemplated by the related agreements between ORIX and the Company also occurred on July 26, 2017. Under the Governance Agreement, ORIX has the right to designate three persons to the Board, which was expanded to nine directors, and also propose a fourth person to be mutually agreed by the Company and ORIX to serve as a new independent director on the Board. In addition, for so long as ORIX is entitled to board representation pursuant to the Governance Agreement, ORIX will be subject to certain customary standstill restrictions, including an effective 25% cap on its voting rights. Pursuant to the Registration Rights Agreement, ORIX also has certain customary registration rights with respect to the shares of the Company’s common stock that it owns. Under the Commercial Cooperation Agreement, the Company has exclusive rights to develop, own, operate and provide equipment for ORIX geothermal energy projects in all markets outside of Japan. In addition, the Company has certain rights to serve as technical partner and co-invest in ORIX geothermal energy projects in Japan. ORIX will also assist the Company in obtaining project financing for its geothermal energy projects from a variety of leading providers of renewable energy debt financing with which ORIX has relationships in Asia and around the world. Viridity transaction
On
Using proprietary software and solutions, Viridity serves primarily retail energy providers, utilities, and large commercial and industrial customers. Viridity’s offerings enable its customers to optimize and monetize their energy management, demand response and storage facilities potential by interacting on their behalf with regional transmission organizations and independent system operators. The Company accounted for the transaction in accordance with Accounting Standard Codification 805, Business Combinations, and consequently recorded intangible assets of $34.7 million primarily relating to Viridity’s storage activities with a weighted-average amortization period of 19 years, approximately $0.4 million of goodwill. Following the transaction, the Company
year ended December 31, 2017.
Guadeloupe power plant transaction
In July 2016,
Pursuant to the terms of an Amended and Restated Investment Agreement (“Investment Agreement”) and Shareholders Agreement with Sageos Holding (“Sageos”), a wholly owned subsidiary of Bureau de Recherches Géologiques et Minières (“BRGM”), the Company together with Caisse des Dépôts et Consignations (“CDC”), a French state-owned financial organization, acquired an approximately 80% interest in GB, allocated 75% to the Company and 25% to CDC.
Pursuant to the agreements, the
The Bouillante power plant sells its electricity under a 15-year PPA that was entered into in February 2016 with Électricité de France S.A. (“EDF”), the French electric utility.
The Company accounted for the transaction based on the provision of Accounting Standard Codification 805, Business Combinations, and consequently
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
Inventories consist of the following:
NOTE
Cost and estimated earnings on uncompleted contracts consist of the following:
These amounts are included in the consolidated balance sheets under the following captions:
The completion costs of the Company’s construction contracts are subject to estimation. Due to uncertainties inherent in the estimation process, it is reasonably possible that estimated contract earnings will be further revised in the near term.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
The Sarulla Project
The Company holds a 12.75% equity interest in a consortium which is in the process of developing the Sarulla geothermal power project in Indonesia with an expected generating capacity of approximately 330
The project is being constructed in three phases of
On May 16, 2014, the consortium closed
The Sarulla consortium entered into interest rate swap agreements with various international banks in order to fix the
The Sarulla project company accounted for the interest rate swap as a cash flow hedge upon which changes in the fair value of the hedging instrument, relative to the effective portion, will be recorded in other comprehensive income. As such, during the
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Pursuant to a supply agreement that was signed in October 2013, the Company is supplying its OECs to the power plant and has added the
During the year ended December 31,
NOTE
The Company’s overall methodology for evaluating transactions and relationships under the variable interest entity (“VIE”) accounting and disclosure requirements includes the following two steps: (i) determining whether the entity meets the criteria to qualify as a VIE; and (ii) determining whether the Company is the primary beneficiary of the VIE.
In performing the first step, the significant factors and judgments that the Company considers in making the determination as to whether an entity is a VIE include:
The design of the entity, including the nature of its risks and the purpose for which the entity was created, to determine the variability that the entity was designed to create and distribute to its interest holders;
The nature of the Company’s involvement with the entity;
Whether there is sufficient equity investment at risk to finance the activities of the entity; and
Whether parties other than the equity holders have the obligation to absorb expected losses or the right to receive residual returns.
If the Company identifies a VIE based on the above considerations, it then performs the second step and evaluates whether it is the primary beneficiary of the VIE by considering the following significant factors and judgments:
Whether the Company has the power to direct the activities of the VIE that most significantly impact the entity’s economic performance; and
Whether the Company has the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.
The Company’s VIEs include certain of its wholly owned subsidiaries that own one or more power plants with long-term PPAs. In most cases, the PPAs require the utility to purchase substantially all of the plant’s electrical output over a significant portion of its estimated useful life. Most of the VIEs have associated project financing debt that is non-recourse to the general creditors of the Company, is collateralized by substantially all of the assets of the VIE and those of its wholly owned subsidiaries (also VIEs) and is fully and unconditionally guaranteed by such subsidiaries. The Company has concluded that such entities are VIEs primarily because the entities do not have sufficient equity at risk and/or subordinated financial support is provided through the long-term PPAs. The Company has evaluated each of its VIEs to determine the primary beneficiary by considering the party that has the power to direct the most significant activities of the entity. Such activities include, among others, construction of the power plant, operations and maintenance, dispatch of electricity, financing and strategy. Except for power plants that it acquired, the Company is responsible for the construction of its power plants and generally provides operation and maintenance services. Primarily due to its involvement in these and other activities, the Company has concluded that it directs the most significant activities at each of its VIEs and, therefore, is considered the primary beneficiary. The Company performs an ongoing reassessment of the VIEs to determine the primary beneficiary and may be required to deconsolidate certain of its VIEs in the future. The Company has aggregated its consolidated VIEs into the following categories: (i) wholly owned subsidiaries with project debt; and (ii) wholly owned subsidiaries with PPAs.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The tables below detail the assets and liabilities (excluding intercompany balances which are eliminated in consolidation) for the Company’s VIEs, combined by VIE classifications, that were included in the consolidated balance sheets as of December 31,
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
The fair value measurement guidance clarifies that fair value is an exit price, representing the amount that would be received upon selling an asset or paid upon transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or liability. The guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under the fair value measurement guidance are described below:
Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities;
Level 2 — Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability;
Level 3 — Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (supported by little or no market activity).
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth certain fair value information at December 31,
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The amounts set forth in the tables above include investments in debt instruments and money market funds (which are included in cash equivalents). Those securities and deposits are classified within Level 1 of the fair value hierarchy because they are valued using quoted market prices in an active market.
The following table presents the amounts of gain (loss) recognized in the consolidated statements of operations and comprehensive income (loss) on derivative instruments not designated as hedges:
On
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On February 24, 2016, the Company entered into Brent Oil Future contracts under which it has written a number of call options covering a notional quantity of approximately 185,000 barrels (“BBL”) of Brent with exercise prices of $32.80 to $35.50 and expiration dates ranging from March 24, 2016 until December 22, 2016 in order to reduce its exposure to fluctuations in Brent prices under its PPA with HELCO. The Company received an aggregate premium of approximately $1.1 million from these call options. The call option contracts have monthly expiration dates whereby the options can be called and the Company would have to settle its liability on a cash basis. Moreover, during March 2016, the Company rolled 2 existing call options covering a total notional quantity of 31,800 BBL of Brent in order to limit its exposure to $41 to $42.50 instead of $32.80 to $33.50. In addition, the Company entered into short risk reversal transactions (sell call and buy put options) by rolling existing call options covering notional quantities of 16,500 BBL and 17,000 BBL in order to limit its exposure from the outstanding call options originally entered into in February 2016 to a range of $28.50 to $37.50 and $28 to $38.50, respectively. On March 6, 2014, and on May 14, 2015, the Company entered into NGI swap contracts with a bank covering a notional quantity of approximately 2.2
The foregoing future, forward and swap transactions have not been designated as hedge transactions and are marked to market with the corresponding gains or losses recognized within “Derivatives and foreign currency transaction gains (losses)”
There were no transfers of assets or liabilities between Level 1, Level 2 and Level 3 during the year ended December 31,
The fair value of the Company’s long-term debt is as follows:
The fair value of the OFC Senior Secured Notes was determined using observable market prices as these securities are traded. The fair value of all the long-term debt is determined by a valuation model, which is based on a conventional discounted cash flow methodology and utilizes assumptions of current borrowing rates
The carrying value of other financial instruments, such as revolving lines of credit and deposits approximates fair value.
162 NOTE
Property, plant and equipment
Property, plant and equipment, net, consist of the following:
Depreciation expense for the years ended December 31, 2017, 2016,
U.S. Operations
The net book value of the property, plant and equipment, including construction-in-process, located in the
Foreign Operations
The net book value of property, plant and equipment, including construction-in-process, located outside of the
The Company, through its wholly owned subsidiary, OrPower 4, Inc. (“OrPower 4”), owns and operates geothermal power plants in Kenya. The net book value of assets associated with the power plants was
The Company, through its wholly owned subsidiary, Orzunil I de Electricidad, Limitada (“Orzunil”), owns a power plant in Guatemala. On January 22, 2014, Orzunil signed an amendment to the PPA with Instituto Nacional de Electrificacion (“INDE”), a Guatemalan power ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company, through its wholly owned subsidiary, Ortitlan, Limitada (“Ortitlan”), owns a power plant in Guatemala. The net book value of the assets related to the power plant was The Company, through its wholly owned subsidiary, GeoPlatanares, signed a Build, Operate and Transfer (BOT) contract for the Platanares geothermal project in Honduras with ELCOSA, a privately owned Honduran energy company, for 15 years from the commercial operation date. Platanares sells the electricity produced by the power plants to ENEE, the national utility of Honduras under a 30-year PPA. The net book value of the assets related to the power plant was $140.3 million and $67.5 million at December 31, 2017 and 2016, respectively. The Company, through its subsidiary, GB, owns a power plant in Guadeloupe. The net book value of the assets related to the power plant was $24.9 million and $20.3 million at December 31, 2017 and 2016, respectively. GB sells the electricity produced by the power plants to EDF, the French electric utility, under a 15-year PPA.
Construction-in-process
Construction-in-process consists of the following:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
Intangible assets amounting to
Estimated future amortization expense for the intangible assets as of December 31,
Goodwill
Goodwill amounting to
NOTE Accounts payable and accrued expenses consist of the following:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
Long-term debt consists of notes payable under the following agreements:
Loan Agreement with Banco Industrial S.A. and Westrust Bank (International) Limited
On July 31, 2015,
The loan is payable in 48 quarterly payments commencing September 30, 2015. The loan bears interest at a rate per annum equal to of the sum of the LIBO Rate (which cannot be lower than 1.25%) plus a margin of (i) 4.35% as long as the Company’s guaranty of the loan (as described below) is outstanding or (ii) 4.75% otherwise. Interest is payable quarterly, on March 30, June 30, September 30 and December 30 of each year, on the stated maturity date of the loan and on any prepayment or payment of the loan. The loan must be prepaid on the occurrence of certain events, such as casualty, condemnation, asset sales and expansion financing not provided by the lenders under the credit agreement, among others. The loan may be voluntarily prepaid if certain conditions are satisfied, including payment of a premium (ranging from
There are various restrictive covenants under the Amatitlan credit agreement. These include, among others, (i) a financial covenant to maintain a Debt Service Coverage Ratio (as defined in the credit agreement) of not less than 1.15 to 1.00 as of the last day of any fiscal quarter and (ii) limitations on Restricted Payments (as defined in the credit agreement) that among other things would limit dividends that could be paid to us unless the historical and projected Debt Service Coverage Ratio is not less than 1.25 to 1.00 for the four fiscal quarterly periods (calculated as a single accounting period). As of December 31,
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The loan is
The Company has guaranteed payment of all obligations under the credit agreement and related financing documents. The guaranty is limited in the sense that the Company is only required to pay the guaranteed obligations if a “trigger event” occurs. A trigger event is the occurrence and continuation of a default by
As of December 31,
Finance Agreement with OPIC (the Olkaria III Complex)
On August 23,2012, OrPower 4, the Company’s wholly owned subsidiary,
The OPIC Loan is comprised of up to three tranches:
In July 2013, we completed the conversion of the interest rate applicable to both Tranche I and Tranche II from a floating interest rate to a fixed interest rate. The average fixed interest rate for Tranche I, which has an outstanding balance as of December 31,
OrPower 4 has a right to make voluntary prepayments of all or a portion of the OPIC Loan subject to prior notice, minimum prepayment amounts, and a prepayment premium of 2.0% in the firsttwo years after the Plant 2 commercial operation date, declining to 1% in the third year after the Plant 2 commercial operation date, and without premium thereafter, plus a redemption premium. In addition, the OPIC Loan is subject to customary mandatory prepayment in the event of certain reductions in generation capacity of the power plants, unless such reductions will not cause the projected ratio of cash flow to debt service to fall below 1.7.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The OPIC Loan is
The finance agreement includes customary events of default, including failure to pay any principal, interest or other amounts when due, failure to comply with covenants, breach of representations and warranties, non-payment or acceleration of other debt of OrPower 4, bankruptcy of OrPower 4 or certain of its affiliates, judgments rendered against OrPower 4, expropriation, change of control, and revocation or early termination of security documents or certain project-related agreements, subject to various exceptions and notice, cure and grace periods.
There are various restrictive covenants under the OPIC Loan, which include a required historical and projected
As of December 31,
Debt service reserve
As required under the terms of the OPIC Loan, OrPower 4 maintains an account which may be funded by cash or backed by letters of credit in an amount sufficient to pay scheduled debt service amounts, including principal and interest, due under the terms of the OPIC Loan in the following six months. This restricted cash account is classified as current in the consolidated balance sheets. As of December 31,
Well drilling reserve
As required under the terms of the OPIC Loan, OrPower 4may be required to maintain an account which may be funded by cash or backed by letters of credit to reserve funds for future well drilling, based on determination upon the completion of the expansion work.
OFC Senior Secured Notes
In February 2004, OFC,
In
In September 2016, the Company repurchased
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
OrCal Senior Secured Notes
In December 2005, OrCal,
OrCal may redeem the OrCal Senior Secured Notes, in whole or in part, at any time at a redemption price equal to the principal amount of the OrCal Senior Secured Notes to be redeemed plus accrued interest, and a “make-whole” premium. Upon certain events, as defined in the indenture governing the OrCal Senior Secured Notes, OrCal may be required to redeem a portion of the OrCal Senior Secured Notes at a redemption price of 100% of the principal amount of the OrCal Senior Secured Notes being redeemed plus accrued interest.
Debt service reserve
As required under the terms of the OrCal Senior Secured Notes, OrCal maintains an account which may be funded by cash or backed by letters of credit (see below) in an amount sufficient to pay scheduled debt service amounts, including principal and interest, due under the terms of the OrCal Senior Secured Notes in the following six months. This restricted cash account is classified as current in the consolidated balance sheets. As of each of December 31,
OFC 2 Senior Secured Notes
In September 2011, OFC 2,the Company’s wholly owned subsidiary, and OFC
Subject to the fulfillment of customary and other specified conditions precedent, the OFC 2 Senior Secured Notes may be issued in up to six distinct series associated with the phased construction (Phase I and Phase II) of the Jersey Valley, McGinness Hills and Tuscarora geothermal power plants, which are owned by the OFC 2 Issuers. The OFC 2 Senior Secured Notes will mature and the principal amount of the OFC 2 Senior Secured Notes will be payable in equal quarterly installments and in any event not later than December 31, 2034. Each series of notes will bear interest at a rate calculated based on a spread over the Treasury yield curve that will be set at least ten business days prior to the issuance of such series of notes. Interest will be payable quarterly in arrears. The DOE will guarantee payment of 80% of principal and interest on the OFC 2 Senior Secured Notes pursuant to Section 1705 of Title XVII of the Energy Policy Act of 2005, as amended. The conditions precedent to the issuance of the OFC 2 Senior Secured Notes includes certain specified conditions required by the DOE in connection with its guarantee of the OFC 2 Senior Secured Notes.
On October 31, 2011, the OFC 2 Issuers completed the sale of
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS On June 20, 2014, Phase 1 of Tuscarora Facility achieved Project Completion under the
On August 29, 2014, OFC 2
In connection with the anticipated
The Company concluded that the cash flow hedge was fully effective with no ineffective portion and no amounts excluded from the effectiveness testing, thus, in 2014, the total loss from the cash flow hedge was fully recognized in “Loss in respect of derivatives instruments designated for cash flow hedge” under other comprehensive income of
The OFC 2 Senior Secured Notes are collateralized by substantially all of the assets of OFC 2 and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC 2. There are various restrictive covenants under the OFC 2 Senior Secured Notes, which include limitations on additional indebtedness of OFC 2 and its wholly owned subsidiaries. Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OFC 2. In addition, there are restrictions on the ability of OFC 2 to make distributions to its shareholders.
Among other things, the distribution restrictions include a historical debt service coverage ratio requirement of at least 1.2 (on a blended basis for all OFC 2 power plants), measured, at the time of any proposed distribution, over each of the two
There were $2
The Company provided a ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Debt service reserve; other restricted funds
Under the terms of the OFC 2 Senior Secured Notes, OFC 2 is required to maintain a debt service reserve and certain other reserves, as follows:
Don A. Campbell Senior Secured Notes — Non-Recourse
On November 29, 2016,
The net proceeds from the sale of the DAC 1 Senior Secured Notes, after deducting certain transaction expenses and the funding of a debt service reserve account, were approximately $87.1 million and ORNI 47
ORNI 47
The DAC 1 Senior Secured Notes constitute senior secured obligations of ORNI 47 and are secured by all of the assets of ORNI 47. Under the ORNI 47 Note Purchase Agreement, ORNI 47may prepay at any time all, or from time to time any part of, the DAC 1 Senior Secured Notes in an amount equal to at least ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31,
Senior Unsecured Bonds
In August 2010, the Company entered into a trust instrument governing the issuance of, and accepted subscriptions for, an aggregate principal amount of approximately
In September 2016, the Company concluded an auction tender and accepted subscriptions for
The
Loans from institutional investors
In July 2009,
Loan Agreements with DEG (the Olkaria III Complex)
In March 2009, OrPower 4,the Company’s wholly owned subsidiary,
On October 20, 2016, OrPower 4 entered into a new
Under the DEG 2
175 NOTE
In 2005, the Company’s wholly owned subsidiary in Hawaii, Puna Geothermal Ventures (“PGV”), entered into transactions involving the original geothermal power plant of the Puna complex located on the Big Island (the “Puna Power Plant”).
Pursuant to a
The Head Lease and the Project Lease are being accounted for separately. Each was classified as an operating lease in accordance with the accounting standards for leases. The Deferred Lease Income is amortized into revenue, using the straight-line method, over the
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Future minimum lease payments under the Project Lease, as of December 31,
Depository accounts
As required under the terms of the lease agreements, there are certain reserve funds that need to be managed by the indenture trustee in accordance with certain balance requirements. Such reserve funds amounted to
Distribution account
PGV maintains an account to deposit its remaining cash, after making all of the necessary payments and transfers as provided for in the lease agreements, in order to make distributions to Ormat Nevada. The distributions are allowed only if PGV maintains various restrictive covenants under the lease agreements, which include limitations on additional indebtedness. As of December 31,
NOTE
On December 16,2016,
In connection with the transactions contemplated by the Equity Contribution Agreement and the LLC Agreement, Ormat Nevada transferred its indirect ownership interest in the McGinness Hills (Phase I and Phase II), Tuscarora, Jersey Valley and second phase of the Don A. Campbell
Pursuant to the Equity Contribution Agreement, JPM contributed approximately
Under the LLC Agreement, until December 31, 2022, OrLeaf will receive distributions of 97.5% of any distributable cash generated by operation of the power plants while JPM will receive distributions of 2.5% of any distributable cash generated by operation of the power plants. Unless JPM has already achieved its target internal rate of return on its investment in Opal Geo, from December 31, 2022 until JPM has achieved its target internal rate of return, JPM will receive ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Under the LLC Agreement, all items of Opal Geo income and loss, gain, deduction and credit (including the federal production tax credits relating to the operation of the two PTC eligible power plants) will be allocated, until JPM has achieved its target internal rate of return on its investment in Opal Geo (and for so long as the two PTC eligible power plants are generating PTCs), 99% to JPM and 1% to OrLeaf, or 5% to JPM and 95% to OrLeaf if PTCs are no longer available to either of the two PTC eligible power plants. Once JPM achieves its target internal rate of return, all items of Opal Geo income and loss, gain, deduction and credit will be allocated 5% to JPM and 95% to OrLeaf.
Under the LLC Agreement, OrLeaf, which owns
The LLC Agreement contains certain customary restrictions on transfer applicable to both OrLeaf and JPM with respect to their respective Membership Interests in Opal Geo, and also provides OrLeaf with a right of first offer in the event JPM desires to transfer any of its Class B Membership Interests, pursuant to which OrLeaf may purchase such Class B Membership Interests. The LLC Agreement also provides OrLeaf with the option to purchase all of the Class B Membership Interests on either December 31, 2022 or the date that is 9 years after the closing date under the Equity Contribution Agreement at a price equal to the greater of (i) the fair market value of the Class B Membership Interests as of the date of purchase (subject to certain adjustments) and (ii)
Pursuant to the Equity Contribution Agreement, the Company has provided a guaranty for the benefit of JPM of certain of OrLeaf’s indemnification obligations to JPM under the LLC Agreement. In addition, Ormat Nevada also provided a guaranty for the benefit of JPM of all present and future payment and performance obligations of OrLeaf under the LLC Agreement and each ancillary document to which OrLeaf is a party.
OPC TRANSACTION
In June 2007, Ormat Nevada entered into agreements with affiliates of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc. (Morgan Stanley Geothermal LLC and Lehman-OPC LLC), under which those investors purchased, for cash, interests in a newly formed subsidiary of Ormat Nevada, OPC LLC (“OPC”), entitling the investors to certain tax benefits (such as
The first closing under the agreements occurred in 2007 and covered the Company’s Desert Peak 2, Steamboat Hills, and Galena 2 power plants. The investors paid
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Ormat Nevada
On October 30, 2009, Ormat Nevada acquired from Lehman-OPC LLC all of the Class B membership units of OPC held by Lehman-OPC pursuant to a right of first offer for a price of
On February 3, 2011, Ormat Nevada sold to JPM all of the Class B membership units of OPC On May 31, 2017, the Company’s partners JPM and Morgan Stanley achieved their target after-tax yield on its investment in OPC and on October 31, 2017, Ormat Nevada purchased all of the Class B membership units in OPC from JPM and Morgan Stanley for $1.9 million. As a result, Ormat Nevada is now the sole owner of all of the economic and voting interests in OPC and continues to consolidate OPC in its financial statements. The purchase of Class B membership units of OPC was recorded in equity as a reduction of $6.5 million to Noncontrolling Interest with the surplus of $8.5 million charged to Additional Paid-in Capital.
ORTP TRANSACTION
In January 2013, Ormat Nevada entered into agreements with JP Morgan (“JPM”) under which JPM purchased interests in a newly formed subsidiary of Ormat Nevada, ORTP, LLC (“ORTP”), entitling JPM to certain tax benefits (such as PTCs and accelerated depreciation) associated with certain geothermal power plants in California and Nevada.
Under the terms of the transaction, Ormat Nevada transferred the Heber complex, the Mammoth complex, the Ormesa complex, and the Steamboat 2 and 3, Burdette (Galena In March2017, JPM achieved its target after-tax yield on its investment in ORTP and on July 10, 2017, Ormat Nevada purchased all of
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
The following table presents a reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligation for the years presented below:
NOTE
The Company makes an estimate of expected forfeitures and recognizes compensation costs only for those stock-based awards expected to vest. As of December 31,
During the years ended December 31, 2017, 2016
During the fourth quarters of 2017,2016
Valuation assumptions
Prior to 2016,
The Company calculated the fair value of each stock-based award on the date of grant based on the following assumptions:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stock-based awards
The 2004 Incentive Compensation Plan
In 2004, the Company’s Board of Directors adopted the 2004 Incentive Compensation Plan
The 2012 Incentive Compensation Plan
In May 2012, the Company’s shareholders adopted the 2012 Incentive Compensation Plan
The 2012 Incentive Plan empowers our Board of Directors, in its discretion, to amend the 2012 Incentive Plan in certain respects. Consistent with its authority to amend the Incentive Plan, in February 2014 the Board adopted and approved certain amendments to the 2012 Incentive Plan. The key amendments are as follows:
Increase of per grant limit: Section
Acceleration of vesting: Section
On February 11, 2014, the Company granted its Chief Financial Officer options to purchase 32,500 shares of common stock under the 2012 Incentive Plan. The exercise price of each option is
The fair value of each stock option on the grant date was
On April 2, 2014, the Company granted its newly appointed Chief Executive Officer options to purchase up to an aggregate of 400,000 shares of common stock under the 2012 Incentive Plan. The exercise price of each option is
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The fair value of each option on the grant date was
On November 5, 2014, the Company granted its directors options to purchase 52,500 shares of common stock under the 2012 Incentive Plan. The exercise price of each option is
The fair value of each stock option on the grant date was
On November 3, 2015, the Company granted its directors options to purchase 45,000 shares of common stock under the 2012 Incentive Plan. The exercise price of each option is
The fair value of each stock option on the grant date was
On June 13, 2016, the Company granted its employees,
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The fair value of each SAR on the grant date was
On November 8, 2016, the Company granted its directors,
The fair value of each SAR on the grant date was
On June 7, 2017, the Company granted its employees, an aggregate of 23,200 SAR’s under the Company’s 2012 Incentive Plan. The exercise price of each SAR is $58.79, which represented the fair market value of the Company’s common stock on the grant date. Such SARs will expire five years from the date of the grant. Such SARs will vest according to a vesting schedule as follows: 50% on the first anniversary of the grant date and 25% on each of the third and fourth anniversaries of the grant date. The fair value of each SAR on the grant date was $13.67. The Company calculated the fair value of each SAR on the grant date using the Exercise Multiple-Based Lattice SAR-Pricing model based on the following assumptions:
On August 4, 2017, the Company granted its directors, an aggregate of 30,000 options under the Company’s 2012 Incentive Plan. The exercise price of each option is $57.97, which represented the fair market value of the Company’s common stock on the grant date. Such options will expire seven years from the date of the grant and will fully vest one year from the grant date. The fair value of each option on the grant date was $18.42. The Company calculated the fair value of each option on the grant date using the Exercise Multiple-Based Lattice SAR-Pricing model based on the following assumptions:
On November 8, 2017, the Company granted its directors and members of its senior management an aggregate of 108,771 SARs and 22,742 Restricted Stock Units (“RSUs”) under the Company’s 2012 Incentive Plan. The exercise price of each SAR is $63.35, which represented the fair market value of the Company’s common stock on the grant date. Such SARs and RSUs will expire in six years and will vest according to a vesting schedule as follows: for the directors, 100% on the firstanniversary of the grant date and for members of senior management, 25%on each of the first, second, third and fourth anniversaries of the grant date.
The fair value of each SAR for the directors and members of senior management on the grant date was $17.6 and $17.7, respectively. The fair value of each RSU for the directors and members of senior management on the grant date was $62.9 and $62.3, respectively. The Company calculated the fair value of each SAR and RSU on the grant date using the Exercise Multiple-Based Lattice Pricing model based on the following assumptions:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
__________
As of December 31,
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes information about stock-based awards outstanding at December 31,
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes information about stock-based awards outstanding at December 31,
The aggregate intrinsic value in the above tables represents the total pretax intrinsic value, based on the Company’s stock price of
The total pretax intrinsic value of options exercised during the year ended December 31,
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
Substantially all of the Company’s electricity revenues are recognized pursuant to PPAs in the U.S. and in various foreign countries, including Kenya and Guatemala. These PPAs generally provide for the payment of energy payments or both energy and capacity payments through their respective terms which expire in varying periods from
Pursuant to the terms of certain of the PPAs, the Company may be required to make payments to the relevant power purchaser under certain conditions, such as shortfall in delivery of renewable energy and energy credits, and not meeting certain performance threshold requirements, as defined in the relevant PPA. The amount of payment required is dependent upon the level of shortfall in delivery or performance requirements and is recorded in the period the shortfall occurs. In addition, if the Company does not meet certain minimum performance requirements, the capacity of the power plant may be permanently reduced.
As discussed in Note 1, the Company assessed all PPAs agreed to, modified or acquired in business combinations on or after July 1, 2003, and evaluated whether such PPAs contained a lease element requiring lease accounting. Future lease revenues under PPAs which contain a lease element as of December 31,
The PPAs considered to be leases were also assessed for inclusion of embedded derivatives, which required that they be separately accounted for at fair value. However, none of such PPAs were determined to include embedded derivatives.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE The components of interest expense are as follows:
NOTE U.S. and foreign components of income
The components of the provision (benefit) for income taxes, net are as follows:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The significant components of the deferred income tax expense (benefit) are as follows:
Reconciliation of the U.S. federal statutory tax rate to the Company’s effective income tax rate is as follows:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The net deferred tax assets and liabilities consist of the following:
The following table presents a reconciliation of the beginning and ending valuation allowance:
At December 31,
The Company has recorded notable deferred tax assets for net operating losses, foreign tax credits, and production tax credits.Realization of the deferred tax assets and tax credits is dependent on generating sufficient taxable income in appropriate jurisdictions prior to expiration of the NOL carryforwards and tax credits. Based upon available evidence of the Company’s ability to generate additional taxable income in the future and historical losses in prior years, a valuation allowance in the amount of
In October 2016, the FASB issued Accounting Standards Update 2016-16, Income Taxes on Intercompany Transfers (ASU 2016- 16), effective in fiscal years beginning after December 15, 2017, for public companies. In general, the
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table presents the deferred taxes on the balance
(1) The non-current deferred tax asset has been reduced by the uncertain tax benefit of $0.1 million in accordance with ASU 2013-11, Income Taxes. During 2017, the Company changed its intention to reinvest certain undistributed earnings of Ormat Systems Ltd., a wholly owned subsidiary in Israel. The decision was made to distribute $396.0 million, of which $300.0 million was received in December 2017 and the remaining $96.0 million is expected to be received during 2018. The Company recorded the tax impact of this change in the income tax provision, notable a withholding tax of approximately $58.3 million. The Company recorded a foreign tax credit deferred tax asset for the withholding tax and an associated valuation allowance based on the Company’s ability to utilize foreign tax credits in the U.S. prior to the expiration period.
The total amount of undistributed earnings of all other foreign subsidiaries for income tax purposes was approximately $
Uncertain tax positions
We are subject to income taxes in the U.S. (federal and state) and numerous foreign jurisdictions. Significant judgment is required in evaluating our tax positions and determining our provision for income taxes. During the ordinary course of business,
At December 31,
A reconciliation of our unrecognized tax benefits is as follows:
The Company and its U.S. subsidiaries file consolidated income tax returns for federal and state purposes. As of December 31,
The reduction of
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company’s foreign subsidiaries remain open to examination by the local income tax authorities in the following countries for the years indicated:
Management believes that the liability for unrecognized tax benefits is adequate for all open tax years based on its assessment of many factors, including among others, past experience and interpretations of local income tax regulations. This assessment relies on estimates and assumptions and may involve a series of complex judgments about future events. As a result, it is possible that federal, state and foreign tax examinations will result in assessments in future periods. To the extent any such assessments occur, the Company will adjust its liability for unrecognized tax benefits.
Tax benefits in the U.S.
The U.S. government encourages production of electricity from geothermal resources through certain tax subsidies under the ARRA which has been extended by the Consolidated Appropriations Act, 2016 (CAA) ● 80% for property placed in service after Dec. 31, 2022 and before Jan. 1, 2024. ● 60% for property placed in service after Dec. 31, 2023 and before Jan. 1, 2025. ● 40% for property placed in service after Dec. 31, 2024 and before Jan. 1, 2026. ● 20% for property placed in service after Dec. 31, 2025 and before Jan. 1, 2027. The Company could also If the Company claims the ITC, the Company’s “tax base” in the plant that it can recover through bonus or accelerated depreciation (if elected) must be reduced by half of the ITC. If the Company claims the PTC, there is no reduction in the tax basis for depreciation. Companies that place qualifying renewable energy facilities in service, during
Income taxes related to foreign operations
Guatemala — The enacted tax rate is 25%. Orzunil, a wholly owned subsidiary, was granted a benefit under a law which promotes development of renewable power sources. The law allows Orzunil to reduce the investment made in its geothermal power plant from income tax payable, which reduces the effective tax rate to zero. Ortitlan, another wholly owned subsidiary, was granted a tax exemption for a period of ten years ending August 2017.Starting August 2017, Ortitlan pays income tax of 7% on its Electricity revenues. The effect of the tax exemption in the years ended December 31, 2017, 2016,
Israel — The Company’s operations in Israel through its wholly owned Israeli subsidiary, Ormat Systems Ltd. (“Ormat Systems”), are taxed at the regular corporate tax rate of In the event of distribution of a cash dividend out of retained earnings which were tax exempt due to prior benefits, Ormat Systems would have to pay tax in respect of the amount distributed. Since the exemptions are contingent upon nondistribution of dividends and since upon liquidation the Company will have to pay a 25% tax on exempt income, Ormat Systems recorded deferred tax liability at the rate of 25% in respect of the tax exempt income in 2004-2008. In the event that Ormat Systems fails to comply with the program terms, the tax benefits may be canceled and it may be required to refund the amount of the benefits utilized, in whole or in part, with the addition of linkage differences and interest. Ormat Systems tax assessment for fiscal years 2010-2014 was finalized and settled in January 2017. The settlement resulted in no impact to income statement due to release of the related uncertain tax position liability.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Kenya - The Company’s operations in Kenya are taxed at the rate of 37.5%. On September 11, 2015, Kenya's Income Tax Act was amended pursuant to certain provisions of the recently adopted Finance Act, 2015. Among other matters, these amendments retain the enhanced investment deduction of 150% under Section 17B of the Income Tax Act, extend the period for deduction of tax losses from 5 years to 10 years under Sections
During the fourth quarter of 2016, the Company determined that its income statement tax provision and deferred tax liabilities in Kenya in prior periods were overstated by approximately $4.7 million as a result of
As previously reported by the Company, the Kenya Revenue Authority (“KRA”) conducted an audit related to the Guadeloupe - The Company’s operations in Guadeloupe are taxed at a rate of 34.43% in 2017, a rate of 28% up to a taxable income of €0.5 million and 33.3% on Honduras - The Company’s operations in Honduras are exempt from income taxes for the first ten years starting at the commercial operation date of the power plant.
Other significant foreign countries — The Company’s operations in New Zealand are taxed at the rate of 28% in 2015,2014 and 2013.
Income taxes related to U.S. tax legislation commonly referred to as the Tax Cuts and Jobs Act
On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”). The Tax Act makes broad and complex changes to the U.S. tax code, including, but not limited to, (1) reducing the U.S. federal corporate tax rate from 35 percent to 21 percent; (2) requiring companies to include in taxable income a one-time tax on certain repatriated earnings of foreign subsidiaries; (3) generally eliminating U.S. federal income taxes on dividends from foreign subsidiaries; (4) a new provision designed to tax global intangible low-taxed income (GILTI); (5) eliminating the corporate alternative minimum tax (AMT) and changing how existing AMT credits can be realized; (6) creating the base erosion anti-abuse tax (BEAT), a new minimum tax; (7) creating a new limitation on deductible interest expense; and (8) changing rules related to uses and limitations of net operating loss carryforwards created in tax years beginning after December 31, 2017. ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The SEC staff issued SAB 118, which provides guidance on accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting under ASC 740. In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Tax Act for which the accounting under ASC 740 is complete. To the extent that a company’s accounting for certain income tax effects of the Tax Act is incomplete but it is able to determine a reasonable estimate, it must record a provisional estimate in the financial statements. If a company cannot determine a provisional estimate to be included in the financial statements, it should continue to apply ASC 740 on the basis of the provision of the tax laws that were in effect immediately before the enactment of the Tax Act. Our accounting for the following elements of the Tax Act is incomplete and the Company may materially adjust these amounts for related administrative guidance, notices, implementing regulations, potential legislative amendments and interpretations as the new tax law evolves. However, we are able to make reasonable estimates of certain effects and, therefore, recorded provisional adjustments as follows:
Deemed Repatriation Transition Tax: The Deemed Repatriation Tax (Transition Tax) is a one-time 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 must determine, 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. We are able to make a reasonable estimate of the Transition Tax and recorded a provisional Transition Tax income inclusion of $71.9 million. The Company has sufficient NOLs to offset such tax inclusions to taxable income, therefore there is no resulting obligation due for such amount. We are continuing to gather additional information to refine the amount computed for Transition Tax. Global intangible low taxed income (GILTI): The Tax Act creates a new requirement that certain income (i.e. GILTI) earned by controlled foreign corporations (CFCs) must be included currently in gross income of the CFC’s U.S. Shareholder. GILTI is the excess of the shareholder’s “net CFC tested income” over the net deemed tangible income return, which is currently defined as the excess of (1) 10 percent of the aggregate of the U.S. shareholder’s pro rata share of the qualified business asset investment of each CFC with respect to which it is a U.S. shareholder over (2) the amount of certain interest expense taken into account in the determination of net CFC-texted income. Because of the complexity of the new GILTI rules, we are continuing to evaluate this provision of the Tax Act and the application of ASC 740. As discussed further below, for valuation allowance purposes, GILTI inclusions were determined using estimates of book income, but the Company will calculate the impact of GILTI as a period cost. Valuation Allowance: The Company must assess whether its valuation allowance analyses are affected by various aspects of the Tax Act (e.g. deemed repatriation of deferred foreign income, GILTI inclusions, new categories of FTCs, interest expense limitations). Since, as discussed herein, the Company has recorded provisional amounts related to certain portions of the Tax Act, any corresponding determination of the need for or change in a valuation allowance is provisional. Uncertain Tax Positions: The Company must assess whether its uncertain tax positions analyses are affected by various aspects of the Tax Act (e.g. deemed repatriation of deferred foreign income, GILTI inclusions, new categories of FTCs, interest expense limitations). Since, as discussed herein, the Company has recorded provisional amounts related to certain portions of the Tax Act, any corresponding determination of the need for or change in an uncertain tax position is provisional. NOTE
The Company has two reporting segments: the Electricity and Product segments. These segments are managed and reported separately as each offers different products and serves different markets. The Electricity segment is engaged in the sale of electricity from the Company’s power plants pursuant to PPAs. The Product segment is engaged in the manufacture, including design and development, of turbines and power units for the supply of electrical energy and in the associated construction of power plants utilizing the power units manufactured by the Company to supply energy from geothermal fields and other alternative energy sources. Transfer prices between the operating segments were determined on current market values or cost plus markup of the seller’s business segment.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Summarized financial information concerning the Company’s reportable segments is shown in the following tables:
(1) Electricity segment assets include goodwill in the amount of $21.0 million and $6.7 million as of December 31, 2017 and 2016, respectively.
Reconciling information between reportable segments and the Company’s consolidated totals is shown in the following table:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company sells electricity and products for power plants and others, mainly to the geographical areas according to location of the customers, as detailed below. The following tables present certain data by geographic area:
The following table presents revenues from major customers:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
Transactions between the Company and related entities, other than those disclosed elsewhere in these financial are summarized below:
Restructuring with the Parent
On February 5, 2015, the Tel Aviv Stock Exchange (“TASE”) approved the listing of the Company’s common stock on the TASE. On February 10, 2015, the Company's common stock was successfully listed on the TASE. The TASE also confirmed that the Company will be included in the
On February 12, 2015, the Company completed the share exchange transaction with its then-Parent entity, Ormat Industries Ltd. ("OIL" or "Parent") following which, the Company became a noncontrolled public company and its public float increased from approximately 40% to approximately 76% of its total shares outstanding. Under the terms of the share exchange, OIL shareholders received 0.2592 shares in the Company for each share in OIL, or an aggregate of approximately 30.2 million shares, reflecting a net issuance of approximately 3.0 million shares (after deducting the 27.2 million shares that OIL held in the Company). Consequently, the number of total shares of the Company outstanding increased from approximately 45.5 million shares to approximately 48.5 million shares as of the closing of the share exchange.
In exchange, the Company also received
Corporate and administrative services agreement with the Parent
Ormat Systems and the Parent had agreements whereby Ormat Systems provided to the Parent, for a monthly fee of $10,000 (adjusted annually, in part based on changes in the Israeli Consumer Price Index), certain corporate administrative services, including the services of executive officers. In addition, Ormat Systems agreed to provide the Parent with services of certain skilled engineers and other research and development employees at Ormat Systems’ cost plus 10%.
Lease agreements with the Parent
Ormat Systems had a rental agreement with the Parent entered into in July 2004 for the sublease of office and manufacturing facilities in Yavne, Israel, for a monthly rent of
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Effective April 1, 2009, Ormat Systems entered into an additional rental agreement with the Parent for the sublease of additional manufacturing facilities adjacent to the current manufacturing facilities in Yavne, Israel. The term of the additional rent agreement was to expire on the same day as the abovementioned lease agreement entered into in July 2004. Pursuant to the additional lease agreement, Ormat Systems paid a monthly rent of
As of February 12, 2015, the above-mentioned agreements are no longer effective as a result of the restructuring transaction described above.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
401(k) Plan
The Company has a
Severance plan
The Company, through Ormat Systems, provides limited non-pension benefits to all current employees in Israel who are entitled to benefits in the event of termination or retirement in accordance with the Israeli Government sponsored programs. These plans generally obligate the Company to pay one month’s salary per year of service to employees in the event of involuntary termination. There is no limit on the number of years of service in the calculation of the benefit obligation. The liabilities for these plans are recorded at each balance sheet date by determining the undiscounted obligation as if it were payable at that point in time. Such liabilities have been presented in the consolidated balance sheets as “liabilities for severance pay”. The Company has an obligation to partially fund the liabilities through regular deposits in pension funds and severance pay funds. The amounts funded amounted to
The Company expects to pay the following future benefits to its employees upon their reaching normal retirement age:
The above amounts were determined based on the employees’ current salary rates and the number of years’ service that will have been accumulated at their retirement date. These amounts do not include amounts that might be paid to employees that will cease working with the Company before reaching their normal retirement age.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
Geothermal resources
The Company, through its project subsidiaries in the
Letters of credit
In the ordinary course of business with customers, vendors, and lenders, the Company is contingently liable for performance under letters of credit totaling
Purchase commitments
The Company purchases 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, the Company enters into agreements with contract manufacturers and suppliers that either allow them to procure goods and services based upon specifications defined by the Company, or that establish parameters defining the Company’s requirements.
At December 31,
Grants and royalties
The Company, through Ormat Systems, had historically, through December 31, 2003, requested and received grants for research and development from the Office of the Chief Scientist of the Israeli Government. Ormat Systems is required to pay royalties to the Israeli Government at a rate of 3.5% to 5.0% of the revenues derived from products and services developed using these grants. No royalties were paid for the years ended December 31,
Lease commitments
At December 31, 201
In 2015, the Company entered into a lease transaction for a fleet of vehicles. The lease transaction was classified as a capital lease and the leased vehicles were classified under Property, Plant and Equipment in total amount of
Contingencies
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In addition, from time to time, the Company is named as a party to various other lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of our business. These actions typically seek, among other things, compensation for alleged personal injury, breach of contract, property damage, punitive damages, civil penalties or other losses, or injunctive or declaratory relief. With respect to such lawsuits, claims and proceedings, the Company accrues reserves when a loss is probable and the amount of such loss can be reasonably estimated. It is the opinion of the Company’s management that the outcome of these proceedings, individually and collectively, will not be material to the Company’s consolidated financial statements as a whole.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 23 — QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
Cash dividend
On U.S. Geothermal transaction On January24,2018 the Company entered into a definitive agreement to acquire U.S. Geothermal Inc. (“U.S. Geothermal”), a renewable energy company focused on the development, production and sale of electricity from geothermal energy. Under the terms of the merger agreement, holders of U.S. Geothermal common stock will receive $5.45 per share in cash. On a fully diluted basis, including payment to U.S. Geothermal’s option holders, the Company will pay total consideration of approximately $109.9 million. The closing of the merger is subject to customary conditions, including receipt of regulatory approvals and approval by persons holding a majority of the outstanding shares of U.S. Geothermal common stock. The transaction is expected to close in the second quarter of 2018. U.S. Geothermal is currently operating geothermal power projects at Neal Hot Springs, Oregon, San Emidio, Nevada and Raft River, Idaho for a total designed net output of 45 MW that currently generate approximately 38 MW, net.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and
Management’s Report on Internal Control over Financial Reporting
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in our conditions, or that the degree of compliance with
Material weakness. In connection with the change in our repatriation strategy and the related release of the US income tax valuation allowance in the second quarter of 2017, we did not perform an effective risk assessment related to our internal controls over the accounting for income taxes. As a result, we identified a deficiency in the design of our internal control over financial reporting related to our accounting for income taxes, which affected the recording of income tax accounts by us in our interim and annual consolidated financial statements during 2017, including audit adjustments to the income tax accounts. This deficiency resulted in immaterial adjustments to income tax expense and deferred tax liabilities, but did not result in a material misstatement in our previously issued interim or annual consolidated financial statements nor does it require a restatement of or change in our consolidated financial statements for any prior interim or annual period. However, this control deficiency could result in a misstatement of the aforementioned balances and disclosures that would result in a material misstatement to the interim or annual consolidated financial statements that would not be prevented or detected. Our management has concluded that this deficiency constitutes a material weakness in our internal control over financial reporting.
The effectiveness of the Company’s internal control over financial reporting as of December 31, Remediation Plan In response to the identified material weakness, our management, with the oversight of the Audit Committee of the Board of Directors, will update its risk assessment process related to income taxes and intends to implement additional control procedures. While certain remedial actions have been completed in the first quarter of 2018 and management has dedicated significant resources and efforts to implement a remediation plan, we continue to actively plan to implement additional control procedures. The remediation efforts, outlined below, are intended both to address the identified material weakness and to enhance our overall financial control environment. However, our management may amend this plan to include additional remedial action in light of its continuing evaluation of the identified deficiency in internal control over financial reporting.
We have: ● implemented specific enhanced controls procedures for the review, analysis and reporting of our income tax accounts, including control procedures of projections that support the deferred tax assets and liabilities; ● engaged an external tax and accounting firm to prepare and review our annual and quarterly income tax provision including to review and recommend additional control enhancements; ● recruited additional tax personnel; and ● enhanced our income tax controls with improved documentation. We intend to: ● evaluate the need to recruit additional tax or accounting personnel during 2018; and ● continue to strengthen our income tax controls with improved documentation, communication and oversight. We have commenced our remediation plan, with the goal of remediating this material weakness as soon as possible, subject to the conclusion by our management that our enhanced internal control over financial reporting is operating effectively following appropriate testing. Changes in Internal Control over Financial Reporting
None.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information required by this Item and not set forth below is incorporated herein by reference to the
The following table sets forth the name, age and positions of our directors, executive officers and persons who are executive officers of certain of our subsidiaries who perform policy making functions for us:
* Performs the functions described in the table, but is employed by Ormat Systems
Audit Committee
ITEM 11. EXECUTIVE COMPENSATION
Information required by this
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information required by this
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information required by this
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information required by this
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) (1) List of Financial Statements
See Index to Financial Statements in Part II, Item 8 of this annual report.
(2) List of Financial Statement Schedules
All applicable schedule information is included in our Financial Statements in Part II, Item 8 of this annual report.
(b) Exhibit Index. We hereby file, as exhibits to this Annual Report, those exhibits listed on the Exhibit Index immediately following the signature page hereto.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: March
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated, on March
(C) EXHIBIT INDEX
101.INS*XBRL Instance Document.* 101.SCH* XBRL Taxonomy Extension Schema Document.* 101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document.* 101.DEF* XBRL Taxonomy Extension Definition Linkbase Document.* 101.LAB* XBRL Taxonomy Extension Label 101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document.*
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