10-K 1 ora20141231_10k.htm FORM 10-K ora20141231_10k.htm

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, 2014

 

Or

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

Commission file number: 001-32347

 

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)

 

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, 2014, 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 $527,942,658 based on the closing price as reported on the New York Stock Exchange. As described herein, the aggregate market value of common stock held by non-affiliates of the registrant increased significantly on February 12, 2015, which is the date on which the share exchange contemplated by the Share Exchange Agreement (as described herein) was completed.

 

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 26, 2015, the number of outstanding shares of common stock, par value $0.001 per share was 48,552,560.

 

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, 2014.



 

 
 

 

  

ORMAT TECHNOLOGIES, INC.

 FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2014

 TABLE OF CONTENTS

 

   

Page No

PART I

ITEM 1.

BUSINESS

6

ITEM 1A.

RISK FACTORS

65

ITEM 1B.

UNRESOLVED STAFF COMMENTS

81

ITEM 2.

PROPERTIES

81

ITEM 3.

LEGAL PROCEEDINGS

81

ITEM 4.

MINE SAFETY DISCLOSURES

82

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

83

ITEM 6.

SELECTED FINANCIAL DATA

85

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

87

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

118

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

119

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

180

ITEM 9A.

CONTROLS AND PROCEDURES

180

ITEM 9B.

OTHER INFORMATION

180

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

181

ITEM 11.

EXECUTIVE COMPENSATION

184

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

184

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

184

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

184

PART IV

ITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

185

SIGNATURES

186

 

 

 
 i

 

  

Glossary of Terms

   

      When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:

   

Term

Definition

AER

Alternative Earth Resources Inc.

Amatitlan Loan

$42,000,000 in initial aggregate principal amount borrowed by our subsidiary Ortitlan from TCW Global Project Fund II, Ltd. 

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.

BLM

Bureau of Land Management of the U.S. Department of the Interior

BOT

Build, operate and transfer

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

Commonwealth Development Corporation

CGC

Crump Geothermal Company LLC

CNE

National Energy Commission of Nicaragua

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

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

EBITDA

Earnings before interest, taxes, depreciation and amortization

EGS

Enhanced Geothermal Systems

EIS

Environmental Impact Statement

ENATREL

Empresa Nicaragüense de Transmision

ENEE

Empresa Nacional de Energía Eléctrica

ENEL

Empresa Nicaragüense de Electricidad 

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.

 

 

 
1

 

 

Term

Definition

EPA

U.S. Environmental Protection Agency

EPC

Engineering, procurement and construction

EPS

Earnings per share

ERC

Kenyan Energy Regulatory Commission

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

FPA

U.S. Federal Power Act, as amended

GAAP

Generally accepted accounting principles

GCCU

Geothermal Combined Cycle Unit

GDC

Geothermal Development Company

GDL

Geothermal Development Limited

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

HELCO

Hawaii Electric Light Company

IFC

International Finance Corporation

IID

Imperial Irrigation District

ILA

Israel Land Administration

INDE

Instituto Nacional de Electrification

INE

Nicaragua Institute of Energy

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

John Hancock

John Hancock Life Insurance Company (U.S.A.)

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

LNG

Liquefied natural gas

Mammoth Pacific

Mammoth-Pacific, L.P.

MACRS

Modified Accelerated Cost Recovery System

MIGA

Multilateral Investment Guaranty 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

 

 

 
2

 

 

Term

Definition

NBPL

Northern Border Pipe Line Company

NIS

New Israeli Shekel

NGI

Natural Gas-California SoCal-NGI Natural Gas price index

NGP

Nevada Geothermal Power

NV Energy

NV Energy, Inc.

NYSE

New York Stock Exchange

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

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

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

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.

 

 

 
3

 

 

Term

Definition

Orzunil

Orzunil I de Electricidad, Limitada, a wholly owned subsidiary of the Company

PG&E

Pacific Gas and Electric Company

PGV

Puna Geothermal Venture, a wholly owned subsidiary of the Company

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

RPM

Revolutions Per Minute

RPS

Renewable Portfolio Standards

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

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

TASG Tel Aviv Stock Exchange

TGL

Tikitere Geothermal Power Limited

Union Bank

Union Bank, N.A.

U.S.  

United States of America

U.S. Treasury

U.S. Department of the Treasury

WHOH

Waste Heat Oil Heaters

 

 

 
4

 

 

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 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 on the energy price component under certain of our PPAs;

 

 

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 United States and other countries in which we operate;

 

 

the enforceability of the long-term PPAs for our power plants;

 

 

contract counterparty risk;

 

 

weather and other natural phenomena including earthquakes, volcanic eruption, drought and other nature disasters;

 

 

the impact of recent and future federal, state and local regulatory proceedings and changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, public policies and government incentives that support renewable energy and enhance the economic feasibility of our projects at the federal and state level in the United States and elsewhere, and carbon-related legislation;

 

 

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;

 

 

 
5

 

 

 

current and future litigation;

 

 

our ability to successfully identify, integrate and complete acquisitions, including risks arising in connection with our acquisition of our former parent company, Ormat Industries Ltd. (also referred to in this annual report as “Ormat Industries”);

 

 

competition from other existing 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;

 

 

the direct or indirect impact on our company’s business resulting from 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;

 

 

development and construction of the Solar PV projects, if any, may not materialize as planned;

 

 

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.

 

PART I

 

ITEM 1. BUSINESS

 

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 primarily engaged in the geothermal and recovered energy power business. We design, develop, build, 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 all of our recovered energy-based plants have been constructed by us. We conduct our business activities in the following two business segments:

 

 

The Electricity Segment — in this segment we develop, build, own and operate geothermal and recovered energy-based power plants in the United States and geothermal power plants in other countries around the world and sell the electricity they generate; and

 

 

The Product Segment — in this segment we design, manufacture and sell equipment for geothermal and recovered energy-based electricity generation, remote power units and other power generating units and provide services relating to the engineering, procurement, construction, operation and maintenance of geothermal and recovered energy-based power plants.

 

 

 
6

 

 

The map below shows our current worldwide portfolio of operating geothermal and recovered energy power plants.

 

 

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 our fiscal year ended December 31, 2014. Additional information concerning our segment operations, including year-to-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”.

 

 
7

 

 

The following chart sets forth a breakdown of our revenues for each of the years ended December 31, 2014 and 2013:

  

Segment Contribution to Revenues

  

The following chart sets forth the geographical breakdown of the revenues attributable to our Electricity and Product Segments for each of the years ended December 31, 2014 and 2013:

 

  

Geographical Breakdown of the Electricity Segment Revenues

 

 

 

 
8

 

 

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 other renewable energy sources, geothermal energy is base load and is generally available all the time. 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 represents 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.

 

During recent years, we have expanded our activity to the Solar PV industry. We are monitoring market drivers with potential for developing Solar PV power plants in locations where we can offer competitively priced power generation. In early 2014, we completed the work on the Solar PV project, which is located near our Heber complex in California, and sold the project in March 2014 as a turnkey project.

 

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.

 

 
9

 

  

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 as of February 15, 2015. The generating capacity of certain of our power plants listed below has been updated to reflect changes in the resource temperature and other factors that impact resource capabilities:

 

                       

Type

Region

Plant

 

Ownership(1)

   

Generating capacity (MW) (2)

   

Region 2014 Capacity Factor

 

Geothermal

California

Ormesa complex

    100 %     54          
   

Heber Complex

    100 %     92          
   

Mammoth Complex

    100 %     29          
   

North Brawley

    100 %     18 (5)        
                          78 %
 

West Nevada

Steamboat complex

    100 %     73 (4)        
   

Brady Complex

    100 %     18          
                          86 %
 

East Nevada

Tuscarora

    100 %     18          
   

Jersey Valley

    100 %     10 (6)        
   

McGinness Hills

    100 %     72 (7)        
   

Don A. Campbell

    100 %     19 (8) (3)        
                          93 %
 

Hawaii

Puna

    100 %     38 (3)        
                          77 %
 

International

Amatitlan

    100 %     20          
   

Zunil

    97 %     23 (9) (2)        
   

Olkaria III Complex

    100 %     110          
                          97 %

Total Geothermal

            594       86 %

REG

 

OREG 1

    100 %     22 (3)        
   

OREG 2

    100 %     22 (3)        
   

OREG 3

    100 %     5.5 (3)        
   

OREG 4

    100 %     3.5 (10)        

Total REG

            53       53 %

Total

            647          

___________

(1)

We own and operate all of our power plants. Financial institutions hold equity interests in two of our consolidated subsidiaries: (i) OPC, which owns the Desert Peak 2 power plant in our Brady complex and the Steamboat Hills, Galena 2 and Galena 3 power plants in our Steamboat complex, and (ii) ORTP, which owns the Heber complex, the Ormesa complex, the Mammoth complex, the Steamboat 2 and 3 and Burdette (Galena 1) power plants both in our Steamboat complex, and Brady power plant in our Brady complex. In the above table, we show these power plants as being 100% owned because all of the generating capacity is owned by either OPC or ORTP and we control the operation of the power plants. The nature of the equity interests held by the financial institutions is described below in Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the heading “OPC Transaction” and “ORTP Transaction.”

 

 

 
10

 

 

(2)

References to generating capacity generally refer to the gross capacity less auxiliary power in the case of all of our existing domestic and foreign power plants, except for the Zunil power plant. We determine the generating capacity figures in these power plants by taking into account resource capabilities. In the case of the Zunil power plant, the capacity revenues are calculated based on 24 MW capacity unrelated to the actual performance of the reservoir until 2019. This column represents our net ownership in such generating capacity.

   
 

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.

  

(3)

In February 2015, we signed a definitive agreement with infrastructure funds managed by Northleaf Capital Partners under which we established a new company, ORPD LLC, that will own Puna Complex, Don A. Campbell, OREG 1, OREG 2, OREG 3 power plants and Northleaf will acquire an approximately 40% equity interest in ORPD LLC. The closing of the transaction, which is subject to customary closing conditions, is expected in the first quarter of 2015. See also in Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the heading “ORPD transaction”.

 

(4)

The generating capacity of the Brady and Steamboat complexes was reduced in 2013 due to a decline in the resource temperature in each of these complexes. See “Description of Our Power Plants” below.

 

(5)

Following recent developments, detailed under “Description of Our Power Plants” below, we have decided to operate the North Brawley power plant at a capacity level of approximately 18 MW.

 

(6)

The generating capacity of the Jersey Valley power plant stabilized during 2014.

 

(7)

The McGinness phase 2 power plant reached commercial operation on February 1, 2015 and increased the McGinness complex to 72 MW.

 

(8)

The Don A. Campbell power plant generating capacity is higher than our original expectations of 16MW.

 

(9)

In January 2014, INDE exercised its right under the PPA to become a partner in the Zunil power plant with three percent (3%) equity interest. Detailed information is provided under “Description of Our Power Plants” below.

 

(10)

The OREG 4 power plant is not operating at full capacity as a result of continued low run time of the compressor station that serves as the plant’s heat source, which is resulting in low power generation.

 

All of the revenues that we currently derive from the sale of electricity are pursuant to long-term PPAs. In addition, approximately 44.3% of our total revenues in the year ended December 31, 2014 from the sale of electricity by our domestic power plants were derived from 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 and development of new power plants and expansion of existing power plants. Our expansion plan includes 85 MW in generating capacity from geothermal power plants in the United States, Kenya and Indonesia that we fully released for construction and are in different stages of construction. In addition, we have several projects worldwide that are either under initial stages of construction or under different stages of development with an aggregate capacity of up to approximately 180 MW.

 

We have a substantial land position across 32 sites, mostly in the U.S., that are expected to support future geothermal development, on which we have started or plan to start exploration activity. This land position is comprised of various leases, exploration concessions for geothermal resources and an option to enter into geothermal leases.

  

Our Product Business (Product Segment)

 

We design, manufacture and sell products for electricity generation and provide the related services described below. Generally, we manufacture products only against customer orders and do not manufacture products for our own inventory.

 

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 power plant owners and operators.

 

 
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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, 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 the same customers described above that we target for the sale of our power units for recovered energy-based power generation. 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 better control over the timing and delivery of required equipment and its related costs.

 

Remote Power Units and Other Generators. We design, manufacture and sell fossil fuel powered turbo-generators with a capacity ranging between 200 watts and 5,000 watts, which operate unattended in extreme hot or cold climate conditions. Our customers include contractors installing gas pipelines in remote areas and off-shore platforms operators and contractors. In addition, we design, manufacture, and sell generators for various other uses, including heavy duty direct-current generators.

 

History

 

We were formed as a Delaware corporation in 1994 by Ormat Industries, our former parent company. 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, eliminating its majority ownership and control of us. Our acquisition of Ormat Industries is described in greater detail below under “Recent Developments.”

 

Industry Background

 

Geothermal Energy

 

Most of our power plants in operation produce electricity from geothermal energy. There are several different sources or methods to obtain 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 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 if 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. In addition, because geothermal energy power plants produce weather-independent power 24 hours a day, the variable operating costs are lower.

 

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-pressurized resources — Another source of geothermal energy is hot water produced from oil and gas production. In some oil and gas fields, water is produced as a by-product of the oil and gas extraction. When the wells are deep, the fluids are often at high temperatures and if the water volume is significant, the hot water can be used for power generation in equipment similar to a geothermal power plant.

 

 
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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. The cooled geothermal fluid is then reinjected back into the reservoir. Ormat’s 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 through the removal system in order to optimize the performance of the steam turbines. 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.

 

 
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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 plant described above.

   

Our Proprietary Technology

 

Our proprietary technology may be used in power plants operating according to the Organic Rankine Cycle, either 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 computerized fluid dynamics 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, performance simulation programs, 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 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. Ormat 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 compared with conventional geothermal steam turbine plants. A conventional geothermal steam turbine plant consumes significant quantities of water, causing depletion of the aquifer, and also requires 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 minimum 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.

 

 
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Other advantages of our technology include simplicity of operation and easy maintenance. For instance, the OEC employs low RPM and a 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. 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 simple cycle gas turbine, low pressure steam, or medium temperature liquid found in the process industries such as refineries and cement plants. In most cases, we attach an additional heat exchanger in which we circulate thermal oil to transfer the heat into the OEC’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 the OEC 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 exhibit, requires no water treatment (since it is air cooled), and does not require the continuous presence of a licensed steam boiler operator on site.

  

Ormat’s REG technology is depicted in the diagram below.

 

 

Patents

 

We have 69 U.S. patents that are still in force (and have approximately 34 U.S. patents pending). These patents and patents 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. The system-related patents cover not only a particular component 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 patents cover subjects such as waste heat recovery related to gas pipelines compressors and industrial waste heat, disposal of non-condensable gases present in geothermal fluids, power plants for very high pressure geothermal resources, two-phase fluids as well as processes related to EGS. A number of 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 terms of our patents range from one year to 18 years. The loss of any single patent would not have a material effect on our business or results of operations.

 

 
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Research and Development

 

We are conducting research and development activities intended to improve plant performance, reduce costs, and increase the breadth of product offerings. The primary focus of our research and development efforts includes continued improvements to our condensing equipment with improved performance and lower cost and land usage and developing new turbines and specialized remote power units.

 

We are also continuing with development of new EGS technologies and their application to increase the fluid supply at our existing plants by enhancing the performance of existing wells without additional drilling. We are undertaking this development effort at our Brady Complex in Nevada in cooperation with national laboratories, with funding support from the DOE. Other research and development activity co-funded by the DOE includes testing of new exploration and drilling technologies and practices.

 

Additionally, we are continuing to evaluate investment opportunities in new companies with technology offering product for renewable energy markets.

 

Market Opportunity

 

Domestic

 

Interest in geothermal energy in the United States remains strong for numerous reasons, including legislative support of renewable portfolio standards, coal and nuclear baseload energy retirement and increasing awareness of the positive value of geothermal characteristics as compared to intermittent renewable technology.

 

Although electricity generation from geothermal resources is currently concentrated mainly in California, Nevada, Hawaii, Idaho and Utah, we believe there may be opportunities for development in other states such as Arizona, New Mexico, Washington and Oregon due to the potential of geothermal resources.

 

In a report issued in April 2014, the GEA identified 124 confirmed and unconfirmed geothermal projects under various phases of consideration or development in 12 U.S. states. The domestic geothermal market experienced modest growth mainly, according to the GEA, due to the uncertainty surrounding federal production tax credit for new projects combined with as lowered demand across the market.

 

The successful implementation of the various confirmed and unconfirmed geothermal projects identified by the GEA is depended on the respective project sponsor’s ability to fully identify the resource, conduct exploration, and carry out development and construction. Accordingly, the GEA’s estimates may not be realized, and differences between the actual number of projects completed and those initially estimated 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

 

An additional factor supporting recent growth in the renewable energy industry is the global concern about the environment. In response to an increasing demand for “green” energy, many countries have adopted legislation requiring, and providing incentives for, electric utilities to sell electricity generated from renewable energy sources. In the U.S., approximately 40 states 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 U.S. geothermal power plants in operation are located) 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 the RPS legislation as the most significant driver for us to expand existing power plants and to build new projects.

 

 
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California

 

According to information posted on the California Public Utilities Commission website, California’s three large investor-owned utilities collectively served 22.27% of their 2013 retail electricity sales with renewable power. These utilities have interim targets each year, with a requirement to attain RPS of 25% by 2016 increasing by two percent every year to 33% by the end of 2020. Publicly-owned utilities in California are also required to procure 33% of retail electricity sales from eligible renewable energy resources by 2020, opening up an additional market of potential off-takers for us even though these utilities do not have interim targets. In addition, a new bill was introduced in California to increase the RPS to 50% by 2030. The bill would require the California Public Utilities Commission to evaluate the cost-effectiveness of renewable energy sources not only in regards to their up-front costs but also for their ability to benefit the grid by supplementing intermittent solar and wind, or by providing base-load electricity generation. The bill, together with the California Governor’s call for a clean energy standard that includes 50% of the state’s electricity from renewable resource by 2030, could benefit geothermal energy, which has the advantage of generating flexible base-load power, and helping Califormia diversify its mix of renewable resource.

 

In 2006, California passed a state climate change law, 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 under AB 32. The regulations set a limit on emissions from sources responsible for emitting 80% of California’s GHGs. On November 2014, the CARB released the results of its ninth auction (which was the first joint auction for California and Québec allowances) reporting that the vintage 2014 auction clearing price was $12.10 per allowance and the future vintage auction clearing price was $11.86 per allowance. All of the available 2014 and future vintage allowances offered were sold.

 

In 2014, Assembly Bill No. 2363 (AB-2363), became effective. AB-2363, which requires the California Public Utilities Commission to adopt, by rulemaking, by December 31, 2015, a methodology for determining the costs of integrating eligible renewable energy resources.

 

Nevada

 

Nevada’s RPS requires NV Energy to supply at least 25% of the total electricity it sells from eligible renewable energy resources by 2025. Nevada’s RPS required, for each of 2013 and 2014, that not less than 18% of electricity sold to Nevada retail customers be met with renewable energy resources and credits, and that not less than 5% of that amount be met with solar resources. According to NV Energy’s RPS Annual Report, in 2013, Nevada Power exceeded both the 2013 RPS requirement and the 2013 solar RPS requirement, achieving 20.4% and 18.2%, respectively. Sierra exceeded both the 2013 RPS requirement and the 2013 solar RPS requirement, with 34.7% and 16.1% respectively.

 

In June 2013, the Nevada state legislature passed three bills that were signed into law and expected to support renewable energy development. Senate Bill (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. Senate Bill (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, Assembly Bill (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’s RPS require each electric utility that sells electricity for consumption in Hawaii to obtain 15% of its net electricity sales from renewable energy sources by December 31, 2015, 20% by December 31, 2020, and 40% by 2030. According to a 2014 filing made with the Hawaii PUC, in 2013, Hawaiian Electric Company and its subsidiaries exceeded the 2013 RPS requirement, achieving a consolidated RPS of 34.4% of retail electricity sales from eligible renewable energy resources, including electrical energy savings from energy efficiency and solar water hearing technologies. Excluding electrical energy savings from energy efficient and solar water hearing technologies, the 2013 renewable generation percentage for the Hawaiian Electric Companies was 18.2%.

 

In addition, the Hawaii Electric Light Company submitted a long term energy plan to the HPUC that includes the target goal of generating 92% of its electricity from renewable energy sources by the year 2030.

 

 
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Other States

 

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 is the first mandatory, market-based carbon dioxide emissions reduction program in the United States. Under RGGI, the participating adopted 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.

 

In addition to RGGI, other states have also established the Midwestern Regional Greenhouse Gas Reduction Accord (Midwest Accord) and the Western Climate Initiative (WCI). The RGGI, the WCI and the Midwest Accord have formed the North America 2050, a Partnership for Progress (NA2050) that facilitates state and provincial efforts to design, promote and implement cost-effective policies that reduce greenhouse gas emissions and create economic opportunities.

 

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. 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

 

At the federal level, in 2011 the EPA’s Tailoring Rule sets thresholds for when permitting requirements under the Clean Air Act’s Prevention of Significant Deterioration and Title V programs apply to certain major sources of GHG emissions. In 2013, President Obama outlined an agenda to help reduce carbon emissions, directing the EPA to complete new pollution standards for both new and existing power plants. The EPA released proposed rules for new fossil fuel fired power plants in September 2013 and for existing fossil fuel-fired power plants in June 2014. In the Clean Power Plan proposal, states identify a path forward using either current or new electricity production and pollution control policies to meet the goals of the proposed program including cutting carbon emission from the power sector by 30% below 2005 levels nationwide by 2030.

  

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, 2014, we are permitted to claim an investment tax credit against our U.S. federal income taxes equal to 30% of certain eligible costs when the project is placed in service. If we failed to meet the start of construction deadline for such a project, then the 30% credit is reduced to 10%. In lieu of the 30% investment tax credit (if the project qualifies), we are permitted to claim a tax credit based on the power produced from a geothermal power plant. These production-based credits, which in 2014 were 2.3 cents per kWh, are adjusted annually for inflation and may be claimed for ten years on the electricity produced by the project and sold to third parties after the project is placed in service. The owner of the power plant may not claim both the 30% investment tax credit and the production-based tax credit. For a new solar plant in the U.S. that is placed in service by December 31, 2016, we are permitted to claim an investment tax credit against our U.S. federal income taxes equal to 30% of certain eligible costs when the project is placed in service. The credit is reduced to 10% for solar projects placed in service after December 31, 2016.

 

Under current tax rules, any unused tax credit has a one-year carry back and a twenty-year carry forward.

 

We are also permitted to depreciate, or write off, most of the cost of the plant. In those cases where we claimed the one-time 30% (or 10%) tax credit or received the Treasury cash grant, our tax basis in the plant that we can recover through depreciation is reduced by one-half of the tax credit or cash grant; if in the future we claim other tax credits, there is no reduction in the tax basis for depreciation. For projects that we placed into service after September 8, 2010 and before January 1, 2012, a depreciation “bonus” will permit us to write off 100% of the cost of certain equipment that is part of the geothermal power plant in the year the plant is placed into service, if certain requirements are met. For projects that are placed into service after December 31, 2011 and before January 1, 2014, a similar “bonus” will permit us to write off 50% of the cost of that equipment in the year the power plant is placed into service. 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.

 

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.

 

 
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Global

 

We believe the global markets continue to present growth and expansion opportunities in both established and emerging markets.

 

According to the last GEA, there are approximately 12,800 MW of new capacity in early stages of development or under construction in 70 countries and territories around the world (excluding the U.S.). Additionally, developers are actively engaged with and exploring 27 gigawatts (GW) of geothermal resource globally that could potentially develop into power plants over the next decade. The GEA estimates that there are over 674 developing geothermal power projects globally, ranging from prospects to projects in the late stages of development.

 

The assessment conducted by the GEA is only an estimate that is based on projects and resource reporting by the geothermal industry. Developer ability to fully develop the resource is dependent upon on its capabilities to identify the resource, 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 requirements under the Kyoto Protocol. The Kyoto Protocol was adopted in Kyoto, Japan, in 1997 and entered into force in 2005. In the Bali Action Plan in 2007 and at Copenhagen in 2009 a long-term vision to limit global warming to two degrees Celsius was advanced, and agreed upon in 2010 at the Cancun Conference. The determination to keep within the two degrees Celsius limit led to the creation of the Durban Platform (ADP), in which developed and developing countries will work on a protocol, legal instrument or agreed outcome with legal force, applicable to all parties to the UN Framework Agreement on Climate Change. The new instrument will need to be adopted in 2015 and implemented from 2020. This will be the goal of the 21st U.N. Climate Change Conference that is scheduled to take place in Paris in late 2015.

 

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:

 

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.

 

In Honduras, where we are planning to build the first geothermal power plant under a BOT agreement, the national government approved the Incentives Act (Decree No.70-2007) providing incentives related to tax exemption 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 defined a target to reach at least 80% renewable energy production by 2038.

 

In Chile, where we have three exploration concessions, the Chilean Renewable Energy Act of 2008 required five percent 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 (ERNC), including solar photovoltaic (PV) and concentrating solar power (CSP), by 2025.

 

Mexico is the world’s fourth largest producer of geothermal energy. Recent studies suggest an over 9,000 MW geothermal potential, of which only 12% is already developed. In December 2013, the Mexican Congress passed a constitutional reform (Energy Reform) in an attempt to increase the participation of private investors in the generation and commercialization of electric energy. According to the Mexico Country Report 2012, there is a large amount of unexploited geothermal potential in Mexico. This reform affects the electricity market by opening the generation and commercialization of electricity to private companies, the transformation of the Federal Electricity Commission to a for-profit public company, and the redefinition of functions and attributions of the Ministry of Energy. The secondary legislation that establishes the attributions of the public entities, procurement regulation, and normative framework for the productive companies of the State was finalized in 2014.

 

 
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Many islands nations depend almost entirely on petroleum to supply their electricity demands. With electricity prices average at US$0.35/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 is believed to be outdated and often unreliable power plants. The larger issue hindering large-scale renewable energy deployments, however, is scale. While 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 generators 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 Guadeloupe, where a geothermal power plant has been operating since 1985, currently there are no other geothermal operating projects in the Caribbean region. Recently, some deep well drilling exploration was performed in a few islands.

 

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 the target of increasing renewable electricity generation to 90% of New Zealand’s total electricity generation by 2025.

 

South East Asia

 

In Indonesia, where we participate in the Sarulla project that is currently under development, the government intends to increase the role of renewable energy sources and aims to have them fulfill 25% of the 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. Those regulations included designating approximately 4,000 MW of geothermal projects in its second phase of power acceleration projects to be implemented by 2014, of which the majority are IPP projects and the remaining state utility PLN projects. These targets were not met and the Indonesian government is in the process of issuing new directives for accelerating the geothermal market, including higher ceiling tariffs which may exceed 13.8 c/kWh. For the IPP sector, certain regulations for geothermal projects have been implemented, providing incentives such as investment tax credits and accelerated depreciation, and pricing guidelines to allow preferential power prices for generators; other regulations are being discussed including those that will ease the allocation of forestry permits. On a macro level, the Government of Indonesia committed at the United Nations Climate Change Conference 2009 in Copenhagen to reduce its CO² emissions by 26% 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 potential.

 

In Kenya, there are already several geothermal power plants, including the only geothermal IPP in Africa, our Olkaria III complex. The Government of Kenya has identified the country's untapped geothermal potential as the most suitable indigenous source of electricity and it aspires to reach 5,000 MW of geothermal power by 2030. To attain such number, GDC was formed to fast track the development of geothermal resources in Kenya. Ormat has as a 51% interest in a consortium that signed a PPA for a 35 MW geothermal power plant in the Menengai area.

 

The governments of Djibouti, Ethiopia, Eretria, Tanzania, Uganda, Rwanda and Zambia are exploring ways to develop geothermal in their countries, mostly through the help of international development organizations such as the World Bank.

 

In January 2014, energy ministers and delegates from 19 countries committed to the creation of the Africa Clean Energy Corridor Initiative, at a meeting in Abu Dhabi, convened by the International Renewable Energy Agency (IRENA). 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.

 

 
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East Africa and South East Asia may benefit from two initiatives announced by President Obama. In June 2013, the Power Africa initiative was announced, pursuant to which the U.S. will invest up to $7.0 billion in sub-Saharan Africa over the next five years with the aim of doubling access to power. The program will partner the U.S. Government with the government of six sub-Saharan countries, among them Kenya, Ethiopia and Tanzania, that have a potential for geothermal energy development. In 2012, President Obama proposed the U.S. Asia Pacific Comprehensive Energy Partnership (USACEP) that encourages U.S. companies to develop renewable energy in South East Asian countries, including Indonesia. The United States will provide up to $6.0 billion to support the Partnership.

 

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 gas generation. For example, in the U.S., the 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 initially targeted the North American market, where we have built over 21 power plants which generate electricity from “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, 15 states currently allow electric utilities to include recovered energy-based power generation in calculating such utilities' compliance with their mandatory or voluntary RPS. In addition, California modified the Self Generation Incentive Program (SGIP), which allows recovered energy-based generation to qualify for a per watt incentive.  North Dakota, South Dakota, and the U.S. Department of Agriculture (through the Rural Utilities Service) have approved recovered energy-based power generation units as renewable energy resources, which qualifies recovered energy-based power generators for federally funded, low interest loans, as a priority for our efforts in this regards.

 

Recovery of waste heat is also considered “environmentally friendly” in the western Canadian provinces. We believe that Europe and other markets worldwide may offer similar opportunities in recovered energy-based power generation.

  

In 2012, the Governor of Utah signed into law Senate Bill 12 (SB12) that enables the sale of electricity directly to large energy users. The direct purchasing, while still in early implementation, could create a market opportunity for our REG units in Utah.

 

In addition, in Colorado the state PUC ruled that Xcel Energy, the largest utility in Colorado, will begin offering a $500/kW incentive for recycled energy projects. The incentive will be paid out over 10 years to developers and manufacturers who convert waste heat from stacks and processes into electricity.

 

In summary, the market for the recovery of waste heat into electricity exists either when the available electricity is expensive or where the regulatory environment facilitates construction and marketing of the power. However, such projects tend to be relatively small (up to 6MW) and we expect the growth to be relatively slow and geographically scattered.

 

 
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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.

 

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 15 years.

 

 

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 they depend on precipitation), which cannot serve baseload capacity because of their intermittent nature.

 

 

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, creating a significant competitive advantage for geothermal energy.  

 

 

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.

 

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.

 

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 communications among our subsidiary that designs and manufactures 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 nine 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 69 U.S. patents in force (and have approximately 34 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.

 

 
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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 leading manufacturer and provider of products and services related to renewable energy. 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 development;

 

 

Expanding operation into global markets – increasing our business development activities in an effort to grow our business in the global markets in both business segments;

 

 

Acquisition of New Assets — acquiring from third parties additional geothermal and other renewable assets;

 

 

Manufacturing and Providing Products and 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 generation;

 

 

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 delivery;

 

 

Development and Construction of Recovered Energy Power Plants — since we utilize the same infrastructure to develop, supply or operate Geothermal and REG projects, we can capitalize on opportunities in the REG markets and continue to add successful projects to both our electricity and product segments in this sector; and

 

 

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 February 12, 2015, we announced the completion of the share exchange, which is the first and primary step of a series of transactions contemplated by the Share Exchange Agreement and Plan of Merger (the “Share Exchange Agreement”), dated as of November 10, 2014, by and among us, Ormat Industries, our then-parent company, and Ormat Systems. One of the key consequences of this transaction was that the number of shares of our common stock held by non-affiliated, “public” shareholders was increased from approximately 40% to approximately 76% of total shares outstanding, which we believe would help elevate trading volume and may increase equity coverage.

 

 

 
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Pursuant to the Share Exchange Agreement, we agreed to acquire Ormat Industries through a share exchange in which we issued 30,203,186 new shares of our common stock to Ormat Industries' shareholders in exchange for all of the outstanding ordinary shares of Ormat Industries, reflecting an exchange ratio of 0.2592 shares of our common stock for each ordinary share of Ormat Industries. Following the satisfaction of the various conditions precedent to closing of the share exchange, including (i) the receipt of approval from the District Court of Tel Aviv – Jaffa of the scheme of arrangement under Israeli law represented by the share exchange; (ii) the approval by the controlling shareholder of the issuance of our shares of common stock to the shareholders of Ormat Industries in connection with the share exchange; (iii) the approval of the Share Exchange Agreement by the shareholders of Ormat Industries; and (iv) the maintenance in full force and effect of a ruling that has been obtained from the Israel Tax Authority confirming the Israeli income tax treatment of the transactions contemplated by the Share Exchange Agreement (the “Israeli Tax Ruling”); the share exchange was completed on February 12, 2015.

 

As previously disclosed, we entered into several agreements in connection with the Share Exchange Agreement, including the following:

 

 

o

     voting agreements with the then principal shareholders of Ormat Industries, FIMI ENRG, Limited Partnership and FIMI ENRG, L.P. (together “FIMI”) and Bronicki Investments Ltd. (“Bronicki”), which, following the share exchange, beneficially own approximately 15.06% and 8.84% of our outstanding shares, respectively. Under these voting agreements, FIMI and Bronicki agreed, among other things, to comply in all respects with the Israeli Tax Ruling applicable to the Ormat Industries shareholders.

 

 

o

     voting neutralization agreements with FIMI and Bronicki, whereby FIMI and Bronicki agreed, among other things, to certain restrictions on their shares of our common stock. Among other things, these voting neutralization agreements:

 

 

require these shareholders to vote all voting securities owned by FIMI and Bronicki and their respective affiliates in excess of 16% and 9%, respectively, of the combined voting power of our shares in proportion to votes cast by the other holders of our voting securities at any time any action is to be taken by our stockholders;

 

 

prohibit the acquisition of our voting securities by FIMI and Bronicki and their respective affiliates if after giving effect to any such acquisition FIMI and Bronicki and their respective affiliates would beneficially own voting securities representing in the aggregate more than 20% and 12%, respectively, of the combined voting power of our shares;

 

 

prohibit, prior to January 1, 2017, the sale of more than 10% of our voting securities owned in the aggregate by FIMI and Bronicki; and

 

 

allow, following January 1, 2017, the sale of our voting securities owned by FIMI and Bronicki only if they are not acting in concert to sell or, if they are, only with 20 days’ prior written notice to us, subject to certain exceptions for public sales and mergers and acquisitions transactions.

     
  prohibit FIMI and Bronicki from renewing their shareholder rights agreement beyond its expiration date, May 22, 2017.

 

 

o

a registration rights agreement whereby FIMI and Bronicki may, subject to certain limitations, require us to prepare and file with the SEC a registration statement to register a public offering of the shares of our common stock held by them, on customary terms and conditions set forth in the agreement.

 

 

On February 5, 2015, we announced that our wholly-owned subsidiary has entered into a binding agreement with infrastructure funds managed by Northleaf Capital Partners (Northleaf) under which Ormat will contribute certain geothermal and recovered energy generation power plants into a newly established holding company subsidiary, ORPD LLC (ORPD), and Northleaf will acquire an approximately 40% equity interest in the ORPD. We will raise approximately $175 million from the transaction. The transaction is expected to close in March 2015, subject to customary closing conditions.

     
   

The power plants that will be contributed to ORPD as part of the transaction include our Puna geothermal power plant in Hawaii, the Don A. Campbell geothermal power plant in Nevada, and nine power plant units across three recovered energy generation assets known as OREG 1, OREG 2, and OREG 3. We will continue to consolidate the ORPD and its assets, and will continue to provide day-to-day management control, operations and maintenance control over the projects.

 

 

 
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On February 5, 2015, the TASE approved the listing of our common stock on the TASE beginning on February 10, 2015 and our common stock is now listed on both the NYSE and the TASE. We are still subject to the rules and regulations of the NYSE and of the SEC. Under the local regime for dual listing, U.S.-listed companies, such as us, may dual-list on the TASE without additional regulatory requirements, using the same periodic reports, financial and other relevant disclosure information that they submit to the SEC and NYSE. However, as a result of the local regime requirements, we have undertaken, as part of the TASE listing, not to issue preferred stock for as long as our shares of common stock are listed on the TASE.

 

 

On February 4, 2015, we announced that the second phase of our McGinness Hills geothermal power plant located in Lander County, Nevada has begun commercial operation. Since February 1, 2015, the complex sells electricity under the amended PPA with NV Energy at a new energy rate of $85.58/MWh with one percent annual escalator through December 2032. Following resource confirmation and excellent performance of the first phase of McGinness Hills, which had been operational since June 2012, the second phase initiated construction in March 2014. The McGinness Hills Phase 2 plant that came on line on February 1, 2015, brought the complex’s total capacity to approximately 72MW. We have a contract with NV Energy to sell energy produced at McGinness Hills through December 2032.

 

 

On December 4, 2014, we announced the signing of an amended and restated PPA with KPLC, paving the way for the expansion of the Olkaria complex. Under the terms of the PPA, we expect to increase the generating capacity of the complex by 24 MW, bringing the complex’s total capacity to 134 MW. The fourth plant is expected to come on line in the second half of 2016 and to sell electricity under a 20 year PPA with KPLC.

 

 

On November 3, 2014, we, through a majority owned subsidiary (the Project Company), signed a 25-year PPA with KPLC and a project implementation and steam supply agreement (PISSA) with Geothermal Development Company (GDC) for the 35MW Menengai geothermal project in Kenya. Under the PISSA agreement, the Project Company will finance, design, construct, install, operate and maintain the Menengai steam plant on a build-own-operate (BOO) basis for 25 years. GDC, which is wholly owned by the Government of Kenya, will develop the geothermal resource, supply the steam for conversion to electricity and maintain the geothermal field through the term of the agreement. The Project Company expects to start construction upon financial closing.

 

 

On November 3, 2014, we, through a wholly owned subsidiary, signed a $22.3 million engineering, procurement and construction (EPC) agreement with the Utah Associated Municipal Power System (UAMPS). We will install an air-cooled Ormat Energy Converter (OEC) at the Kern River Transmission Company’s Veyo natural gas compressor station in Southern Utah. This new recovered energy generation (REG) project will generate power using heat that would otherwise have not have been utilized.

 

 

On September 30, 2014, we repaid in full the outstanding amount of approximately $30.0 million from our $42.0 million loan with EIG Global Project Fund II, Ltd. (formerly TCW). The $42.0 million loan was signed in 2009 to refinance Ormat's investment in the 20 MW Amatitlan geothermal power plant located in Guatemala. The loan was scheduled to mature on June 15, 2016 and bears interest at a rate of 9.83%. This repayment resulted in a one-time charge to interest expense of approximately $1.1 million. We are currently negotiating a new financing agreement that we believe will contain improved terms.

 

 

On August 29, 2014, we announced the signing of a $140.0 million loan under the OFC 2 senior secured notes to finance the construction of the McGinness Hills Phase 2 plant in Nevada. This drawdown is the last tranche under the Note Purchase Agreement with John Hancock Life Insurance Company (USA) and guaranteed by the U.S. Department of Energy’s Loan Programs Office in accordance with and subject to the Department’s Loan Guarantee Program under Section 1705 of Title XVII of the Energy Policy Act of 2005. The $140.0 million loan, which matures in December 2032, carries a 4.61% coupon with principal to be repaid on a quarterly basis. The OFC 2 Notes, which include loans for the Tuscarora, Jersey Valley and McGinness Hills complexes, are rated “BBB” by Standard & Poor’s.

 

 

 
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On August 5, 2014, we signed a definitive Purchase and Sale Agreement with Alternative Earth Resources Inc. (AER), pursuant to which we paid $1.5 million in cash in consideration for (i) AER's 50% interest in Crump Geyser and North Valley geothermal project assets and (ii) an option, exercisable over a four-year period, to purchase certain of AER's New Truckhaven geothermal asset.

 

 

On July 1, 2014, Mr. Isaac Angel assumed the position of CEO of our company. He succeeded Mrs. Yehudit (Dita) Bronicki, who announced her retirement in November 2013. Mrs. Bronicki continues to serve as director of Ormat in a non-executive capacity. In addition, effective June 30, 2014, Mr. Gillon Beck stepped down from his position of Chairman of the Board of Directors of the Company and Mr. Yoram Bronicki assumed the position of Chairman. Mr. Beck continues to serve as a director of the Company. Upon assuming the position of the Chairman of the Board, Mr. Yoram Bronicki relinquished his position as President and Chief Operating Officer of the Company.

 

 

On May 23, 2014, we announced the closing of the $1.17 billion financing agreements entered into by the Sarulla consortium for the 330-megawatt (MW) project in North Sumatra in Indonesia. The Japan Bank for International Cooperation (JBIC), the Asian Development Bank and six commercial banks provided the Sarulla project construction and term loans under a limited recourse financing package backed by political risk guarantees from JBIC. The consortium expects the first phase of operations to commence in 2016. The remaining two phases of operations are scheduled to commence within 18 months thereafter. We will supply our Ormat Energy Converters to the power plants and we added the $254.0 million supply contract to our Product Segment backlog. According to the current project plan, we started to recognize revenue from the project during the third quarter of 2014 and will continue to recognize revenues over the course of the next three to four years.

 

 

On March 26, 2014, we signed an agreement with RET Holdings, LLC to sell the Heber Solar project in Imperial County, California for $35.25 million. We received the first payment of $15.0 million in the first quarter of 2014 and the second payment for the remaining $20.25 million in the second quarter of 2014. We recognized pre-tax gain of $7.6 million in the second quarter of 2014.

  

 

On February 4, 2014, we announced that we successfully completed construction and reached commercial operation of Plant 3 in the Olkaria III geothermal power plant complex in Kenya. With Plant 3 online, the complex's total generation capacity has increased to 110 MW. The power generated by the Olkaria III complex is sold under a 20-year PPA with KPLC. On November 25, 2013, we announced that we drew down the remaining $45.0 million comprising Tranche III of the previously announced $310.0 million project finance facility with OPIC.

 

 

On January 23, 2014, we announced that we successfully completed the scope of work needed to bring the Mammoth G1 geothermal power plant in Mono County, California to full capacity. The 6 MW plant reached commercial operation under the new PPA with Pacific, Gas and Electric (PG&E) that allows for hourly energy deliveries of up to 7.5 MW and, as of December 26, 2013, it received the full commercial rate defined in the PPA.

 

 

On January 22, 2014, we announced that one of our wholly owned subsidiaries signed an amendment to the PPA with INDE for the Zunil geothermal power plant in Guatemala, which extends the term of the PPA from 2019 to 2034. The amendment also transfers operation and management responsibilities of the Zunil geothermal field from INDE to Ormat for the term of the amended PPA in exchange for a tariff increase. Additionally, INDE exercised its right under the PPA to become a partner in the Zunil power plant and to acquire a three percent equity interest therein.

 

 

On January 6, 2014, we announced that we completed the construction of the 16 MW Don A. Campbell geothermal power plant in Mineral County, Nevada. The Don A. Campbell facility, formerly Wild Rose, receives a full rate of $99.0 per MWh with no annual escalation under the terms of the PPA, signed in April 2013, with Southern California Public Power Authority (SCPPA). SCPPA resells the power from the Don A. Campbell geothermal power plant to the Los Angeles Department of Water and Power (LADWP) and Burbank Water and Power through NV Energy Inc.’s transmission system.

 

 

 
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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 power plant. Our purpose in establishing a separate subsidiary for each plant is to ensure that the 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 plant. If we do not own all of the interest in a power plant, we enter into a shareholders 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 interest 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, with the exception of the Puna complex, which is an Exempt Wholesale Generator, 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 recently 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’s 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. Acquisition of 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 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 obtain first the exploration license and once certain investment requirements are met, we can obtain the 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 United States are regulated by the BLM and the Minerals Management Service. These agencies have rules governing the geothermal leasing process as discussed above under “Description of Our Leases and Lands”.

 

 
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For most of our current exploration sites in the U.S., we acquire rights to use 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’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, 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 for 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) to deeper (2000-4000 ft) wells as confidence improves. Following proven temperature in core wells, we typically move to slim and/or full- 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 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.

 

 

 
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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 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 takes approximately two years from the time we drill a production well, until the power plant becomes operational.

 

Drilling Production Wells. We consider completing the drilling of first production well as the beginning of our construction phase for a power plant. However, it is not always sufficient for a full release for construction. The number of production wells varies from plant to plant depending, 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 to maintain the geothermal resource and surface conditions. We generally drill the production wells ourselves although in some cases we use outside contractors.

 

The cost for each production well varies depending, 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. Our typical cost for each production well is approximately $4.0 million with a range of $1.0 million to $10.0 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.

 

 
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During the year ended December 31, 2014, in the Electricity Segment we focused on the completion of the Olkaria III plant 3 and the construction of the McGinness Hills phase 2 power plant and began construction in the Don A. Campbell phase 2. We began construction in the Olkaria III plant 3 and McGinness Hills phase 2 during the year ended December 31, 2013, and the Olkaria III Plant 2 during the year ended December 31, 2012.

  

During the year ended December 31, 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. During the year ended December 31, 2013, we discontinued exploration and development activities at three sites, including Magic Reservoir in Idaho, Wildhorse (Mustang) in Nevada and Drum Mountain in Utah. During the year ended December 31, 2012, we discontinued exploration and development activities at five sites, including Leach Hot springs, Hyder Hot Springs, Seven Devil, Smith Creek and Walker River in Nevada.

 

After conducting exploratory studies and drilling in those sites, we concluded that the geothermal resource would not support commercial operations at that time. Costs associated with exploration activities at these sites were expensed accordingly (see “Write-off of Unsuccessful Exploration Activities” under Item 7 — “Management Discussion and Analysis of Financial Condition and Results of Operations”).

  

We added to our exploration activities four, two and five sites during the years ended December 31, 2014, 2013 and 2012, respectively. 

 

How We Operate and Maintain Our Power Plants. In the U.S. we usually employ our subsidiary, Ormat Nevada, to act as 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. 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.

 

How We Sell Electricity. In the U.S., the purchasers of power from our power plants are typically investor-owned electric utility companies. Outside of the United States, 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 called PPAs) for the sale of electricity or the conversion of geothermal resources into electricity. Although a power plant’s revenues under a PPA previously 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, 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 our domestic power plants located in California are eligible for capacity bonus payments under the respective PPAs upon reaching certain levels of generation.

 

 
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How We Finance Our Power Plants. Historically we have funded our power plants with a combination of non-recourse or limited recourse debt, including lease financing, internally generated cash, which includes funds from operation, as well as proceeds from loans under corporate credit facilities, sale of securities, and other sources of liquidity. 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 plant subsidiaries to us are contingent on compliance with financial and other covenants contained in the 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 ratios and certain other conditions, available funds may be disbursed for management fees or dividends or, where there are subordinated lenders, to 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 the 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 interest is typically subject both to a pledge in favor of the power plant’s lenders securing the power plant’s debt and to transfer and change of control restrictions set forth in the relevant financing agreements.

 

Limited recourse debt refers to project financing as described above with the addition of our agreement to undertake limited financial support for our affiliate that owns the power plant in the form of certain limited obligations and contingent liabilities. These obligations and contingent liabilities may take the form of guarantees of certain specified obligations, indemnities, capital infusions and agreements to pay certain debt service deficiencies. 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. To the extent of these limited recourse obligations, creditors of a project financing of a particular power plant may have direct recourse to us.

 

We have also used financing structures to monetize PTCs and other favorable tax benefits derived from the financed power plants and an operating lease arrangement for one of our power plants.

 

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 contracts are with the Multilateral Investment Guaranty Agency (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 revenue loss resulting from a specified governmental act 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 all of our foreign power plants in operation.

 

 
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Description of Our Leases and Lands

 

We have domestic leases on approximately 374,176 acres of federal, state, and private land in Alaska, California, Hawaii, Idaho, Nevada, New Mexico, Oregon and Utah. The approximate breakdown between federal, state, private leases and owned land is as follows:

 

 

72% are leases with the U.S. government, acting through the BLM;

 

 

15% are leases with private landowners and/or leaseholders;

 

 

11% are leases with various states, none of which is currently material; and

 

 

2% are owned by us.

 

Each of the leases within each of the categories has standard terms and requirements, as summarized below. Internationally, our land position includes approximately 174,000 acres, most of which are geothermal exploration licenses in three prospects in Chile.

 

Bureau of Land Management (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 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.

 

 
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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 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.

 

 
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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.

 

Exploration Concessions in Chile

 

We have been awarded six exploration concessions in Chile, under which we had the rights to start exploration work with an original term of two years. Prior to the last six months of the original term of each exploration concession, we could request its extension for an additional period of two years. According to applicable regulations, the extension of the exploration concession is subject to the receipt by the Ministry of Energy of evidence that at least 25% of the planned investments for the execution of the project, as reflected in the relevant proposal submitted during the tender process, has been invested. Following submission of the request, the Ministry of Energy has three months in which it may grant or deny the extension. We have waived three of the six concessions we held. As of the date of this annual report we have the exclusive right to apply for an exploitation license for the remaining three sites. Our exclusive rights will expire on March 7, 2016, and obtaining such license is subject to an approval by the Ministry of Energy.

 

Description of Our Power Plants

 

Domestic Operating Power Plants

 

The following descriptions summarize certain industry metrics for our domestic operating power plants:

 

Brady Complex

 
   

Location

Churchill County, Nevada
   

Generating Capacity

18MW
   

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 eight injection wells are connected to the plants through a gathering system.

   

Major Equipment

Three OEC units and three steam turbines along with the Balance of Plant equipment.

   

Age

The Brady power plant commenced commercial operations in 1992 and a new OEC unit was added in 2004. The Desert Peak 2 power plant commenced commercial operation in 2007.

   

Land and Mineral Rights

The Brady complex area is comprised mainly of BLM leases. 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 in “Description of Our Leases and Lands”.

 

 

 
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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 pursuant to the leases, and the Brady power plant holds right of ways from the BLM and from the private owner that allows access to and from the plant.

   

Resource Information

The resource temperature at Brady is 273 degrees Fahrenheit and at Desert Peak 2 is 340 degrees Fahrenheit.

   

 

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 NNE-trending band of hot ground that extends for a distance of two miles.
   

 

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 NNE-trending folds.
   

 

Geologic structure in the area is dominated by high-angle normal faults of varying displacement.
   

Resource Cooling

Approximately four degrees Fahrenheit per year was historically observed at Brady, and two degrees Fahrenheit was observed in 2013. The temperature decline at Desert Peak is approximately two degrees Fahrenheit per year. At Desert Peak, two formally idle wells were connected for injection and two former injection were shut in to reduce the rate of cooling.

   

Sources of Makeup Water

Condensed steam is used for makeup water.

   

Power Purchaser

Brady power plant — Sierra Pacific Power Company. Desert Peak 2 power plant — Nevada Power Company.

   

PPA Expiration Date

Brady power plant — 2022. Desert Peak 2 power plant — 2027.

   

Financing

OFC Senior Secured Notes and ORTP Transaction in the case of Brady, and OPC Transaction in the case of Desert Peak 2.

   

Don A. Campbell Project

 
   

Location

Mineral County, Nevada
   

Generating Capacity

19 MW
   

Number of Power Plants

One
   

Technology

The Don A. Campbell power plant utilizes an air cooled binary system.

   

Subsurface Improvements

Five production wells and three injection wells are connected to the plant.

   

Material Equipment

One air cooled OEC unit with the Balance of Plant equipment.

   

Age

The power plant is in its second year of operation.

   

Land and Mineral Rights

The Don A. Campbell area is comprised of BLM leases.

   

 

Since we declared commercial operation, the leases are held by production, as described above in “Description of Our Leases and Lands”.
   

 

The project’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”.

 

 

 
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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 five pumped production wells (from depths of 1,350 to 1,900 feet) and three injection wells (from depths of 649 to 2,477 feet), all targeting northwest-dipping fractures. The thermal fluids are thought to be controlled by a combination of conductive heat transfer from deeper bedrock and through mixing of upwelling thermal fluids from a deeper geothermal system also contained in the bedrock. The system is considered blind with no surface expression of thermal features.

   

 

The temperature of the resource is approximately 262 degrees Fahrenheit.
   

Resource Cooling

From the beginning of operation the 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 Expiration Date

2034
   

Financing

Corporate funds and cash grant that we received from the U.S. Treasury.

   

Supplemental Information

In February 2015, we signed a definitive agreement with Northleaf under which we established a new company, ORPD LLC, that will own Puna Complex, Don A. Campbell, OREG 1, OREG 2, OREG 3 power plants and Northleaf will acquire an approximately 40% equity interest in ORPD LLC. The agreements will be in effect at closing expected in the first quarter of 2015, subject to customary closing conditions. Discussed in Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the heading “ORPD transaction”.

   

Heber Complex

 
   

Location

Heber, Imperial County, California
   

Generating Capacity

92 MW (See supplemental information below).
   

Number of Power Plants

Five (Heber 1, Heber 2, Heber South, Gould 1 and Gould 2).

   

Technology

The Heber 1 plant is a dual flash system with a binary bottoming unit called Gould-1 and the Heber 2 group is comprised of the Heber 2, Gould 2 and Heber South plants which all utilize binary systems. The complex uses a water cooled system.

   

Subsurface Improvements

31 production wells and 34 injection wells connected to the plants through a gathering system.

   

Major Equipment

17 OEC units and one steam turbine with the Balance of Plant equipment.

   

Age

The Heber 1 plant commenced commercial operations in 1985 and the Heber 2 plant in 1993. The Gould 1 plant commenced commercial operation in 2006 and the Gould 2 plant in 2005. The Heber South plant commenced commercial operation in 2008.

   

Land and Mineral Rights

The total Heber area is comprised mainly of private leases. 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”.
   

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.

 

 

 
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Resource Information

The resource supplying the flash flowing Heber 1 wells averages 347 degrees Fahrenheit. The resource supplying the pumped Heber 2 wells averages 317 degrees Fahrenheit.

   

 

Heber 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

An average 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

Two PPAs with Southern California Edison and one PPA with SCPPA.
   

PPA Expiration Date

Heber 1 — 2015, Heber 2 — 2023, and Heber South — 2031. The output from the Gould 1 and Gould 2 power plants is sold under the PPAs of Southern California Edison and SCPPA.

   

Financing

OrCal Senior Secured Notes and ORTP Transaction.

   

Supplemental Information

In 2013, we entered into a new PPA with SCPPA, which will replace the current Heber 1 PPA with Southern California Edison upon the expiration of the current PPA expected at the end of 2015.

   

 

In 2012, we drilled a new well as an upgrade project for the Heber 1 area to make better use of the available resource. We drilled two additional wells in 2013 and four old wells were decommissioned. In 2015, we intend to drill one more well and perform upgrades to surface equipment. At the end of this process, we expect the capacity of the complex to reach 92MW.
   

Jersey Valley Power Plant

 
   

Location

Pershing County, Nevada
   

Generating Capacity

10 MW (see supplemental information below).
   

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. The third production well is not connected to the power plant and will be used in the future as required.

   

Major Equipment

Two OEC units together with the Balance of Plant equipment.

   

Age

Construction of the power plant was completed at the end of 2010 and the off-taker approved commercial operation status under the PPA effective on August 30, 2011.

   

Land and Mineral Rights

The Jersey Valley area is comprised of BLM leases. 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 plant.

 

 

 
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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 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 320 degrees Fahrenheit.

   

Resource Cooling

The rate of cooling was six degree Fahrenheit in 2014.

   

Power Purchaser

Nevada Power Company

   

PPA Expiration Date

2032
   

Financing

Corporate funds and ITC cash grant from the U.S. Treasury.

   

 

Once the Jersey Valley power plant reaches certain operational targets and meets other conditions precedent, we have the ability to borrow additional funds under the OFC 2 Senior Secured Notes.
   

Supplemental Information

In 2014, we increased the injection capacity of the Jersey Valley power plant, which has been limiting generation in its early years. Following the work we believe the power plant can operate at a stable capacity of 10MW.

 

 

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 operations in 1984 and G-2 and G-3 commenced commercial operation in 1990. We recently replaced the equipment at the G-1 plant with new OECs.

   

Land and Mineral Rights

The total Mammoth area is comprised mainly of BLM leases. 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”.
   

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.

 

 

 
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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 no scaling potential.
   

Resource Cooling

In the last two years the temperature has stabilized and there is no notable decline, although one degree Fahrenheit per year was observed during the prior 20 years of production.

   

Power Purchaser

G1 and G3 - PG&E and G2 -Southern California Edison.

   

PPA Expiration Date

G-1 and G-3 — 2034, G-2 and— 2027.
   

Financing

OFC Senior Secured Notes and ORTP Transaction.

   

Supplemental Information

In 2012, we entered into two new PPAs with PG&E, which replaced the current G-1 (December 2013) and G-3 PPAs (April 2013) with Southern California Edison.

   

 

In January 2014, we announced that we completed the scope of work needed to bring the G1 geothermal power plant to full capacity. The plant reached commercial operation under the new PPA with PG&E and now receives the full commercial rate defined in the PPA.
   

McGinness Hills Complex

 
   

Location

Lander County, Nevada
   

Generating Capacity

72 MW
   

Number of Power Plants

Two
   

Technology

The McGinness Hills complex utilizes an air cooled binary system.

   

Subsurface Improvements

10 production wells and five injection wells are connected to the power plant.

   

Material Equipment

Six air cooled OEC units with the Balance of Plant Equipment.

   

Age

The first phase commenced commercial operation on July 1, 2012, and the second phase on February 1, 2015.

   

Land and Mineral Rights

The McGinness Hills area is comprised of private and BLM leases.

   

 

The leases are currently held by the payment of 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 “Description of Our Leases and Lands”.
   

Resource Information

The McGinness 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, 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 337 degrees Fahrenheit and the fluids are sourced from the reservoir at elevations between 2,000 to 5,000 feet below the surface.

 

 

 
39

 

 

 

The average temperature of the resource is approximately 335 degrees Fahrenheit.
   

Resource Cooling

The temperature has been stable since the first phase began operation with no notable 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.

   

Power Purchaser

Nevada Power Company
   

PPA Expiration Date

2033
   

Financing

OFC 2 Senior Secured Notes and ITC cash grant from the U.S. Treasury.

   

North Brawley Power Plant

 
   

Location

Imperial County, California
   

Generating Capacity

18 MW (See supplemental information below)
   

Number of Power Plants

One
   

Technology

The North Brawley power plant utilizes a water-cooled binary system.

   

Subsurface Improvements

36 wells have been drilled and are connected to the plants through its gathering system. As we improved our knowledge of the reservoir, we moved some of the wells between production and injection and left some idle. Currently, we have 13 wells connected to the production header and 23 wells, connected to the injection header.

   

Major Equipment

Five OEC units together with the Balance of Plant equipment.

   

Age

The power plant commenced commercial operation on March 31, 2011.

   

Land and Mineral Rights

The total North Brawley area is comprised 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”.
   

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

North 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 North Brawley power plant.

   

 

The average produced fluid resource temperature is 335 degrees Fahrenheit.
   

Resource Cooling

We have not observed a noticeable cooling.

 

 

 
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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

Since the North Brawley power plant was placed in service in 2010, it has been much more difficult to operate its geothermal field than other fields, and the power plant has been unable to reach its design capacity of 50 MW.

   

 

We plan to continue to sell the generated power from the North Brawley plant to Southern California Edison under the existing PPA at a capacity level of approximately 18 MW. We intend to refrain from additional capital investment to expand the capacity and reduce the operational costs of the North Brawley power plant until further geological analysis is completed and/or a higher energy rate will be secured.
   

 

During the fourth quarter of 2012, we recognized an impairment charge of $229.1 million for this plant.
   

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 OEC units.

   

Major Equipment

Four WHOH and four OEC units together with the Balance of Plant equipment.

   

Age

The OREG 1 power plant commenced commercial operations in 2006.

   

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 February 2015, we signed a definitive agreement with Northleaf under which we established a new company, ORPD LLC, that will own Puna Complex, Don A. Campbell, OREG 1, OREG 2, OREG 3 power plants and Northleaf will acquire an approximately 40% equity interest in ORPD LLC. The agreements will be in effect at closing expected in the first quarter of 2015, subject to customary closing conditions. Discussed in Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the heading “ORPD transaction”.

 

 

 
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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 OEC units.

   

Major Equipment

Four WHOH and four OEC units together with the Balance of Plant equipment.

   

Age

The OREG 2 power plant commenced commercial operations during 2009.

   

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 February 2015, we signed a definitive agreement with Northleaf under which we established a new company, ORPD LLC, that will own Puna Complex, Don A. Campbell, OREG 1, OREG 2, OREG 3 power plants and Northleaf will acquire an approximately 40% equity interest in ORPD LLC. The agreements will be in effect at closing expected in the first quarter of 2015, subject to customary closing conditions. Discussed in Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the heading “ORPD transaction”

   

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 OEC units.

   

Major Equipment

One WHOH and one OEC unit along with the Balance of Plant equipment.

   

Age

The OREG 3 power plant commenced commercial operations during 2010.

   

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 February 2015, we signed a definitive agreement with Northleaf under which we established a new company, ORPD LLC, that will own Puna Complex, Don A. Campbell, OREG 1, OREG 2, OREG 3 power plants and Northleaf will acquire an approximately 40% equity interest in ORPD LLC. The agreements will be in effect at closing expected in the first quarter of 2015, subject to customary closing conditions. Discussed in Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the heading “ORPD transaction”

 

 

 
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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 OEC units.
   

Major Equipment

Two WHOH and one OEC unit together with the Balance of Plant Equipment.

   

Age

The OREG 4 power plant commenced commercial operations during 2009.

   

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.
   

Supplemental Information

The OREG 4 power plant was tested for impairment in the third quarter of 2012 due to continued low run time of the compressor station that serves as its heat source, which resulted in low power generation and revenue.

   

 

As a result, during the third quarter of 2012 we recognized an impairment charge of $7.3 million for this plant.
   

Ormesa Complex

 
   

Location

East Mesa, Imperial County, California
   

Generating Capacity

54 MW
   

Number of Power Plants

Four (OG I, OG II, GEM 2 and GEM 3)
   

Technology

The OG plants utilize a binary system and the GEM plants utilize a flash system. The complex uses a water cooling system.

   

Subsurface Improvements

31 production wells and 53 injection wells connected to the plants through a gathering system.

   

Material Major Equipment

32 OEC units and two steam turbines with the Balance of Plant equipment.

   

Age

The various OG I units commenced commercial operations between 1987 and 1989, and the OG II plant commenced commercial operation in 1988. Between 2005 and 2007 a significant portion of the old equipment in the OG plants was replaced (including turbines through repowering). The GEM plants commenced commercial operation in 1989, and a new bottoming unit was added in 2007.

   

Land and Mineral Rights

The total Ormesa area is comprised of BLM leases. 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”.
   

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.

 

 

 
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Resource Information

The resource temperature is an average of 304 degrees Fahrenheit. Production is from sandstones.

   

 

Productive sandstones are between 1,800 and 6,000 feet, and have only matrix permeability. The currently developed thermal anomaly was created in geologic time by conductive heating and direct outflow from an underlying convective fracture system. Produced fluid salinity ranges from 2,000 ppm to 13,000 ppm, and minor scaling and corrosion potential is chemically inhibited.
   

Resource Cooling

One degree Fahrenheit per year was observed during the past 20 years of production.

   

Sources of Makeup Water

Water is provided by the IID.
   

Power Purchaser

Southern California Edison under a single PPA.
   

PPA Expiration Date

2018
   

Financing

OFC Senior Secured Notes and ORTP Transaction.

   

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

Five production wells and four injection wells connected to the plants through a gathering system.

   

Major Equipment

One plant consists of ten OEC units made up of ten binary turbines, ten steam turbines and two bottoming units along with the Balance of Plant equipment. The second plant consists of two OEC units along with Balance of Plant equipment.

   

Age

The first plant commenced commercial operations in 1993. The second plant was placed in service in 2011 and commenced commercial operation in 2012.

   

Land and Mineral Rights

The Puna area 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.

 

 

 
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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

Operating Lease and ITC cash grant from the U.S. Treasury.
     

Supplemental Information

Following the Hurricane Iselle that hit the Big Island of Hawaii in August 2014, we were required to temporarily shut down our Puna power plant. As a result, one of the production wells did not fully recover and the plant lost approximately 5MW. We started the drilling of a sixth production well and the conversion of one of the drilled wells into an injection well.

     

 

The pricing for the energy that is sold from the Puna complex is as follows:
     

 

For the first on-peak 25 MW, the energy price has not changed from HELCO avoided cost.

     

 

For the next on-peak 5 MW, the price has changed from a diesel-based price to a flat rate of 11.8 cents per kWh escalated by 1.5% per year.

     

 

For the new on-peak 8 MW, the price is 9 cents per kWh for up to 30,000 MWh/year and 6 cents per kWh above 30,000 MWh/year, escalated by 1.5% per year.

     

 

For the first off-peak 22 MW the energy price has not changed from avoided cost.

     

 

The off-peak energy above 22 MW is dispatchable:
     

 

1.

For the first off-peak 5 MW, the price has changed from diesel-based price to a flat rate of 11.8 cents per kWh escalated by 1.5% per year.

     

 

2.

For the energy above 27 MW (up to 38 MW) the price is 6 cents per kWh, escalated by 1.5% per year.

     

 

The capacity payment for the first 30 MW remains the same ($160 kW/year for the first 25 MW and $100.95 kW/year for the additional 5 MW). For the new 8MW power plant the annual capacity payment is $2 million.
     

 

We signed a definitive agreement with Northleaf under which we established a new company, ORPD LLC, that owns Puna Complex, Don A. Campbell, OREG 1, OREG 2, OREG 3 power plants and Northleaf will acquire an approximately 40% equity interest in ORPD LLC. The agreements will be in effect at closing expected in the first quarter of 2015, subject to customary closing conditions. Discussed in Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the heading “ORPD transaction”.
     

Steamboat Complex

   
     

Location

Steamboat, Washoe County, Nevada
     

Generating Capacity

73 MW
     

Number of Power Plants

Six (Steamboat 2 and 3, Burdette (Galena 1), Steamboat Hills, Galena 2 and Galena 3).

 

 

 
45

 

 

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

24 production wells and nine injection wells connected to the plants through a gathering system. We intend to tie into the plant in 2015 one new production well and one new injection well that were drilled in 2014.

   

Major Equipment

10 individual air cooled OEC units and one steam turbine together with the Balance of Plant Equipment.

   

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 is an average of 285 degrees Fahrenheit.

   

 

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

Historically, the resource temperature declined at two degrees Fahrenheit per year, however, since the expansion of the complex, the rate of decline has been approximately five degrees Fahrenheit per year (see “Supplemental Information” below).

   

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

OFC Senior Secured Notes and ORTP Transaction (Steamboat 2 and 3, and Burdette (Galena1)) and OPC Transaction (Steamboat Hills, Galena 2, and Galena 3)

 

 

 
46

 

 

Supplemental information

In an attempt to increase the output of the plant we have acquired land adjacent to the complex and are evaluating a resource development program on that land. Tracer tests and reservoir modeling showed that three injection wells were causing most of the cooling. We shut down these wells and a new injection well was drilled in 2014 in the new land which we expect will reduce the complex cooling. We are planning to further optimize the field in 2015 to reduce the cooling and maximize power output.

   

Tuscarora Power Plant

 
   

Location

Elko County, Nevada
   

Projected Generating Capacity

18 MW
   

Number of Power Plants

One
   

Technology

The Tuscarora power plant utilizes a water cooled binary system.

   

Subsurface Improvements

Three production and six injection wells are connected to the power plant.

   

Major Equipment

Two water cooled OEC units with the Balance of Plant equipment.

   

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 resource temperature averages 339 degrees Fahrenheit.
   

Resource Cooling

We expect gradual decline in the cooling trend from two degrees Fahrenheit per year in the next two to three years, to less than one degree Fahrenheit per year over the long term.

   

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 and ITC cash grant from the U.S. Treasury.

   

Foreign Operating Power Plants

 
   

 

The following descriptions summarize certain industry metrics for our foreign operating power plants:

 

 

 
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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 (1 MW).

   

Subsurface Improvements

Five production wells and two injection wells connected to the plants through a gathering system.

   

Major Equipment

One steam turbine and two OEC units together with the Balance of Plant equipment.

   

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 from April 2003. Leased and company owned property is approximately three percent 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 and two percent of revenues exceeding 20.5 MW.

   

 

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 524 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 project loan from TCW Global Project Fund II, Ltd., which we repaid in full in September 2014. Currently, we are looking to finance the project with financial institution.

   

Olkaria III Complex (Kenya)

 
   

Location

Naivasha, Kenya
   

Generating Capacity

110 MW
   

Number of Power Plants

Four (Olkaria III Phase 1 and Olkaria III Phase 2, together Plant 1, Plant 2 and Plant 3).

   

Technology

The Olkaria III complex utilizes an air cooled binary system.

 

 

 
48

 

 

Subsurface Improvements

16 production wells and four injection wells connected to the plants through a gathering system.

   

Major Equipment

11 OEC units together with the Balance of Plant equipment.

   

Age

Plant 3 commenced commercial operation in January 2014 and plant 2 in April 2013. The first phase of Plant 1commenced operation in 2000 and the second phase in 2009.

   

Land and Mineral Rights

The total Olkaria III area is comprised of government leases. A license granted by the Kenyan government provides exclusive rights of use and possession of the relevant geothermal resources for an initial period of 30 years, expiring in 2029, which initial period may be extended for two additional five-year terms. The Kenyan Minister of Energy has the right to terminate or revoke the license in the event work in or under the license area stops during a period of six months, or there is a failure to comply with the terms of the license or the provisions of the law relating to geothermal resources. Royalties are paid to the Kenyan government monthly based on the amount of power supplied to the power purchaser and an annual rent.

   

 

The power generated is purchased at the metering point located immediately after the power transformers in the 220 kV sub-station within the power plant, before the transmission lines which belong to the utility.
   

Resource Information

The resource temperature is an average of 570 degrees Fahrenheit.

   

 

The Olkaria III geothermal field is on the west side of the greater Olkaria geothermal area located at approximately 6,890 feet above sea level within the Rift Valley.
   

 

Hot geothermal fluids rise up from deep in the northeastern portion of the concession area, penetrating a low permeability zone below 3,280 feet above sea level to a high productivity, two-phase zone identified between 3,280 and 4,270 feet ASL.
   

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 pursuant to the lease agreement.

   

Power Purchaser

KPLC
   

PPA Expiration Date

2033
   

Financing

Senior secured project finance loan from OPIC and a subordinated loan from DEG.

   

Supplemental Information

We recently signed an amended and restated PPA with KPLC, Under the terms of the PPA, we expect to increase the generating capacity of the complex by 24 MW, bringing the complex’s total capacity to 134 MW. The fourth plant is expected to come on line in the second half of 2016 and to sell electricity under a 20 years PPA with KPLC

   

Zunil Power Plant (Guatemala)

 
   

Location

Zunil, Guatemala
   

Generating Capacity

24 MW
   

Number of Power Plants

One
   

Technology

The Zunil power plant utilizes an air cooled binary system.

 

 

 
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Subsurface

Six production wells and two injection wells are connected to the plant through a gathering system.

   

Major Equipment

Seven OEC units together with the Balance of Plant equipment.

   

Age

The plant commenced commercial operation in 1999.

   

Land and Mineral Rights

The land owned by the plant includes the power plant, workshop and open yards for equipment and pipes storage.

   

 

Pipelines for the gathering system transit through a local agricultural area’s right of way acquired by us.
   

 

The geothermal wells and resource are owned by INDE.
   

 

Our produced power is sold at our property line; power transmission lines are owned and operated by INDE.
   

Resource Information

The Zunil geothermal reservoir is hosted in Tertiary volcanic rocks which include overly fractured granodiorite. Production wells produce a reservoir from 536-572 degrees Fahrenheit to a depth of approximately 2,860-4,300 feet. A shallow steam cap exists in the production area of the field, and most of the wells produce high enthalpy fluid due to the presence of two-phase conditions in their feed zones. The wells target northwest- and northeast-trending fractures for permeability. These fractures are also thought to control upwelling from the volcanically-heated source. The upwelling fluids form a steam cap, and fluids and steam reach the surface along fractures, forming springs and fumaroles throughout the geothermal field.

   

Resource Cooling

The resource temperature is stable.

   

Access to Property

Direct access to public roads.

   

Power Purchaser

INDE
   

PPA Expiration Date

2034
   

Supplemental Information

In January 2014, we signed an amendment with INDE to extend the term of the PPA by 15 years until 2034.

   

 

The PPA amendment also transfers operation and management responsibilities of the Zunil geothermal field from INDE to Ormat for the term of the amended PPA in exchange for an increase in tariff. Additionally, INDE exercised its right under the PPA to become a partner in the Zunil power plant and to hold a three percent equity interest.
   

 

Currently, the power plant generates approximately 9.5 MW due to lack of sufficient geothermal resource supply. We plan to improve the heat supply to gradually increase generation, subject to monitoring and assessment of the geothermal reservoir. We expect that this improvement and the increase in tariff will increase the energy portion of revenues. We plan to drill a new production well in 2015 that we expect will increase output by 5 MW to 10 MW.
   

 

According to the PPA amendment, payments for the Zunil plant will be made as follows:

 

 

1.

Capacity payment:

       

 

  a.

Until 2019, the capacity payment will be calculated based on 24 MW capacity regardless of the actual performance of the power plant.

       

 

  b.

From 2019 and onwards, the capacity payment will be based on actual delivered capacity and the capacity rate will be reduced.

 

 

 
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2.

Energy payment:

       

 

  a.

From January 2014 until 2034, the energy payment will include a geothermal field O&M rate based on actual delivered energy in addition to the energy rate on actual delivered energy.

       

 

  b.

From 2019 and onwards, the energy rate on delivered energy will increase and will compensate the reduction in capacity price.

 

Projects under Construction 

 

We are in varying stages of construction of projects, some of them we fully released and are in different stages of construction and two projects are each in an initial stage of construction.

 

The following is a description of projects in Nevada, Kenya and Indonesia with an expected total generating capacity of approximately 86 MW that were released and are in different stages of construction.

 

Don. A. Campbell Phase 2 (U.S.)

 
   

Location

Mineral County, Nevada
   

Projected Generating Capacity

19 MW
   

Projected Technology 

Phase 2 power plant will utilize a binary system.

   

Condition

Field development and construction have begun

   

Land and Mineral Rights

The Don A. Campbell area is comprised of BLM leases.

   

 

Since we declared commercial operation of Don A. Campbell phase 1, the leases are held by production, as described above in “Description of Our Leases and Lands”.
   

 

The project’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 Don A. Campbell geothermal reservoir consists of highly fractured, silicified alluvium over at least two square miles. Production and injection are very shallow with five pumped production wells (from depths of 1,350 to 1,900 feet) and three injection wells (from depths of 649 to 2,477 feet), all targeting northwest-dipping fractures. The thermal fluids are thought to be controlled by a combination of conductive heat transfer from deeper bedrock and through mixing of upwelling thermal fluids from a deeper geothermal system also contained in the bedrock. The system is considered blind with no surface expression of thermal features.

   

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

The PPA for this power plant is in approval process of the off-taker

   

Financing

Corporate funds
   

Projected Operation

First quarter-2016

   

Supplemental Information

In February 2015, we signed a definitive agreement with Northleaf under which we established a new company, ORPD LLC, that will own Puna Complex, Don A. Campbell, OREG 1, OREG 2, and OREG 3 power plants and Northleaf will acquire an approximately 40% equity interest in ORPD LLC. Once Don A. Campbell phase 2 is completed and tested it will be added to ORPD LLC at a price agreed upon with Northleaf. The agreements will be in effect at closing expected in the first quarter of 2015, subject to customary closing conditions. The agreements are discussed in Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the heading “ORPD transaction”.

 

 

 
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Olkaria III – Plant 4 (Kenya)

 
   

Location

Naivasha, Kenya

   

Projected Generating Capacity

24MW

   

Projected Technology

Plant 4 will utilize an air cooled binary system.

   

Condition

Field development of Plant 4 is in its final stage and site construction has started

   

Subsurface Improvement

Two new production wells are planned to be drilled.

   

Land and Mineral Rights

The total Olkaria III area is comprised of government leases. See description above under “Olkaria III Complex”.

   

Resource Information

The Olkaria III geothermal field is on the west side of the greater Olkaria geothermal area located within the Rift Valley at approximately 6,890 feet above sea level.

   

 

Hot geothermal fluids rise up from deep in the northeastern portion of the concession area through low permeability at a shallow depth to a high productivity two-phase region from 3,280 to 4,270 feet above sea level.
   

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 Purchaser

20 years from COD of Plant 4.

   

Financing

Corporate finance

   

Projected Operation

Second half of 2016

   

Supplemental Information

We amended and restated the existing PPA with KPLC. The amended and restated PPA provides for the construction of a new 24 MW power plant bringing the complex's total capacity to 134 MW. Two new production wells are planned to be drilled.

   
Sarulla (Indonesia)  
   
Location Tapanuli Utara North Sumatra, Indonesia. One site is located in Silangkitan (SIL) and the two other sites in Namura I Langit (NIL) area.
   
Ownership Sarulla Operation LTD (SOL) is a consortium consists of Medco Energi Internasional Tbk,Itochu Corporation, Kyushu Electric Power Co. Inc., and one of our wholly owned subsidiaries that hold 12.75% interest.
   
Projected Generating Capacity Approximately 330 MW
   
Projected Technology Integrated Geothermal Combined Cycle Unit comprised of 3 back pressure steam turbines and 18 OEC units.
   
Condition Field development is ongoing. Engineering, procurement and Construction are in progress. Infrastructure work has completed.
   
Land and Mineral Rights All land for the project was acquired.
   
Resource Information Two field areas, NIL and SIL host a liquid-dominated system. Previously drilled wells have temperatures from 275°C to 310°C. Flow tests of the first SOL partnership well, N2n-1, predict 22 NMW single well capacity with 751 T/hr total flow and 125 T/hr steam flow at 12.5 bar and 1126 kJ/kg. Both fields are within a tectonic half graven adjacent to the Great Sumatran Fault. In addition to highly encouraging drilling results, extensive surface manifestations, including fumaroles, boiling hot springs, and alteration, highlight an extensive area of productivity.
   
Access to Property Access to property for the project has been secured
   
Power Purchaser 30-year Energy Sales Contract with PT PLN (the state electric utility)
   
Financing In May, 2014, the consortium reached financial closing of $1.17 billion to finance the development of the project with a consortium of lenders comprised of Japan Bank for International Cooperation (“JBIC”), the Asian Development Bank and six commercial banks and obtained construction and term loan under limited recourse financing package backed by political risk guarantee from JBIC. 

 

 
52

 

 

Projected Operation The project will be constructed in three phases of approximately 110 MW each, utilizing both steam and brine extracted from the geothermal field to increase the power plant’s efficiency. The first phase of operations is expected to commence in 2016 and the remaining two phases of operations are scheduled to commence within 18 months thereafter.
   
Supplemental Information The Sarulla project will be owned and operated by the consortium members under the framework of a JOC and ESC. Under the JOC, PT Pertamina Geothermal Energy (PGE), the concession holder for the project, has provided the consortium with the right to use the geothermal field, and under the ESC, PT PLN, the state electric utility, will be the off-taker at Sarulla for a period of 30 years. 
   
  In addition to our equity holdings in the consortium, we designed the Sarulla plant and will supply our OECs to the power plant.

 

The following is a description of projects in California and Nevada with an expected total generating capacity of 50 MW that are each in an initial stage of construction:
   

Carson Lake Project (U.S.)

 
   

Location

Churchill County, Nevada
   

Projected Generating Capacity

20 MW
   

Projected Technology

The Carson Lake power plant will utilize a binary system.

   

Condition

Initial stage of construction; currently on hold.

   

Subsurface Improvements

On hold.

   

Land and Mineral Rights

The Carson Lake area is comprised of BLM leases.

   

 

The leases are currently held by the payment of annual rental payments, as described above in “Description of Our Leases and Lands.”
   

 

Unless steam is produced in commercial quantities, the primary term for these leases will expire commencing August 31, 2016.

 

 
53

 

 

 

The project’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 in leases from BLM.

   

Resource Information

The expected average temperature of the resource cannot be estimated as field development has not been completed yet.

   

Power Purchaser

We have not executed a PPA.
   

Financing

Corporate funds.
   

Projected Operation

To be determined.
   

Supplemental Information

Permitting documentation for the power plant was completed; however, we are still experiencing delays in the permitting process for the transmission line.

   

CD4 Project (Mammoth Complex) (U.S.) 

 
   

Location

Mammoth Lakes, California
   

Projected Generating Capacity

30 MW
   

Projected Technology

The CD4 power plant will utilize an air cooled binary system.

   

Condition

Initial stage of construction.

   

 Subsurface Improvements

We have completed one production well and one injection well. Continued drilling is subject to receipt of additional permits.

   

Land and Mineral Rights

The total Mammoth area is comprised mainly of BLM leases, which are held by production and are the subject of a unitization agreement.

   

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 expected average temperature of the resource cannot be estimated as field development has not been completed yet.

   

Power Purchaser

We have not executed a PPA.
   

Financing

Corporate funds.
   

Projected Operation

To be determined.
   

Supplemental Information

As part of the process to secure a transmission line, we are participating in the Southern California Edison Wholesale Distribution Access Tariff Transition Cluster Generator Interconnection Process (WDAT LGIA) to deliver energy into the Southern California Edison system at the Casa Diablo Substation. Southern California Edison completed phase I and phase II cluster studies and the WDAT LGIA is being reviewed while re-evaluation of the system upgrades is being completed due to changes in the participants in the cluster study.

   

Future Projects 

 

   

Projects under Various Stages of Development

 

We also have projects under various stages of development in the United States, Kenya, and Honduras. 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.

 

 
54

 

  

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 the geothermal projects would be up to approximately 58 MW (representing our interest). However, we prioritize our investments based on their readiness for continued construction and expected economics and therefore we are not planning to invest in all of such projects in 2015.

 

e-Bay REG Project (U.S.)

 

 In September 2013, we entered a Joint Development Agreement with eBay Inc. The Joint Development Agreement allows Ormat and eBay Inc. to advance negotiations on a 20-year term contract and begin preliminary development work to supply cleaner electricity to eBay Inc.'s new Salt Lake City-based data center.

 

Platanares Project (Honduras)

 

In December 2013, we completed the asset acquisition of the Geotérmica Platanares geothermal project in Honduras from ELCOSA, a privately owned Honduran energy company, upon satisfaction of the required conditions precedent. We will hold the assets, including the project’s wells, land, permits and a PPA for up to 35 MW with ENEE, the national utility of Honduras, under a BOT structure for 15 years from commercial operation of the first phase. Under certain circumstances the agreement can be extended by up to one year.

 

Platanares is a late-stage development geothermal project whose previous owners conducted exploration work. Once the well field is appraised, we will determine the expected capacity and begin construction on the first phase anticipated to be approximately 18 MW and to reach commercial operation in 2017.

 

Menengai Project (Kenya)

 

On November 3, 2014, our majority owned Kenyan subsidiary (the Project Company) owned by Ormat (51%), Symbion Power LLC (24.5%) and Civicon Ltd. (24.5%),signed a 25-year PPA with Kenya Power and Lightning Co. Ltd. (KPLC) and a project implementation and steam supply agreement (PISSA) with Geothermal Development Company (GDC) for the 35MW Menengai geothermal project in Kenya.

 

 
55

 

  

Under the PISSA agreement, the Project Company will finance, design, construct, install, operate and maintain the Menengai steam plant on a build-own-operate (BOO) basis for 25 years. GDC, which is wholly owned by the Government of Kenya, will develop the geothermal resource, supply the steam for conversion to electricity and maintain the geothermal field through the term of the agreement. The Project Company expects to start construction upon financial closing.

  

Exploration Prospects

 

We have a substantial land position that is expected to support future development on which we have started or plan to start exploration activity. Our land position is comprised of various leases and private land for geothermal resources of approximately 284,678 acres in 27 prospects including the following:

 

Nevada [12]

 

1.

Aqua Quieta

Completed exploration studies;

2.

Argenta

Under exploration studies;

3.

Baltazar

Completed exploration studies;

4.

Beowawe

Under exploration studies;

5.

Dixie Hope

Under exploratory drilling

  6.    Edwards Creek Under exploratory drilling;
         
  7.   Hycroft Under exploration studies;
         
  8.   North Valley Under exploration studies;
         
  9.   South Jersey Lease acquired but no further action has yet been taken;
         
  10.   Trinity Under exploration studies;
         
  11.   Tungsten Mountain Under exploratory drilling; and
         
  12.   Tuscarora Completed exploration studies.

  

California [4]

 

1.

East and North Brawley

Deep resource lease acquired but no further action has yet been taken;

2.

Glamis

Lease acquired but no further action has yet been taken;

3.

Rhyolite Plateau

Lease acquired but no further action has yet been taken; and

4.

Truckhaven

Under exploration studies.

 

Hawaii [3]

 

1. 

Kona

Under exploration studies.

2.

Kula

Lease acquired but no further action has yet been taken; and

3.

Ulupalakua (Maui)

Completed exploration studies.

 

Oregon [3]

 

1.

Glass Buttes — Midnight Point

Started exploratory drilling;

2.

Newberry — Twilight

Started exploratory drilling; and

3.

Lakeview/ Goose Lake

Completed exploration studies.

 

 

 
56

 

 

Utah [1]

 

1.

Whirlwind Valley

Under exploration studies.

 

New Mexico [1]

 

1.

Rincon

Completed exploration studies.

 

Guatemala [2]

 

1.

Amatitlan Phase II

Exploration studies underway and are subject to acquisition of additional land; and

2.

Tecumburu

Under exploration studies.

 

New Zealand [1]

 

1.

Tikitere

Signed BOT agreement; exploratory drilling is pending resource consent acceptance

 

In addition, we have exploration concessions for geothermal resources of approximately 144,000 acres in the following prospects:

 

Chile [3]

 

1.

Mariman

Under exploration studies;

2.

Quinohuen

Under exploration studies; and

3.

Sollipulli

Under exploration studies.

 

We also have an option to enter into geothermal leases covering more than 44,000 acres under a lease option agreement with Weyerhaeuser Company and agreement to conduct exploration activity at Warm Springs Tribe. We are currently exploring the following prospects:

 

Oregon [2]

 

1.

Winema

Started exploration studies; and

2.

Warm Springs Tribe

Started exploration studies.

 

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 consideration for the power units is usually paid in installments, in accordance with milestones set 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 expires in part upon delivery of the equipment to the site and fully expires at the termination of the warranty period. The guarantees are typically supported by letters of credit.

 

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.

 

 

The first business model, which is similar to the model utilized in our geothermal power generation business, consists of the development, construction, ownership, and operation of recovered energy-based generation power plants. In this case, we will enter into agreements to purchase industrial waste heat, and enter into long-term PPAs with off-takers to sell the electricity generated by the REG unit that utilizes such industrial waste heat. The power purchasers in such cases generally are investor-owned electric utilities or local electrical cooperatives.

 

 

 
57

 

 

 

 

Pursuant to the second business model, we construct and sell the power units for recovered energy-based power generation to third parties for use in “inside-the-fence” installations or otherwise. Our customers include gas processing plant owners and operators, cement plant owners and operators and companies in the process industry.

 

 

Remote Power Units and other Generators. We design, manufacture and sell fossil fuel powered turbo-generators with a capacity ranging between 200 watts and 5,000 watts, which operate unattended in extreme hot or cold climate conditions. The remote power units supply energy for remote and unmanned installations and along communications lines and cathodic protection along gas and oil pipelines. Our customers include contractors installing gas pipelines in remote areas. In addition, we manufacture and sell generators for various other uses, including heavy duty direct current generators. The terms of sale of the turbo-generators are similar to those for the power units produced for power plants.

 

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 the same customers described above that we target for the sale of our power units for recovered energy-based power generation. Unlike many other companies that provide EPC services, we have an advantage in that we are using our own manufactured equipment and thus have better control over the timing and delivery of required equipment and its costs. The consideration for such services is usually paid in installments, in accordance with milestones set in the EPC contract and related documents. We usually provide performance guarantees or letters of credit securing our obligations under the contract. Upon delivery of the plant to its owner, such guarantees are replaced with a warranty guarantee, usually for a period ranging from 12 months to 36 months. The EPC contract usually places a cap on our liabilities for failure to meet our obligations thereunder.

 

In connection with the sale of our power units for geothermal power plants, power units for recovered energy-based power generation and remote power units and other generators, we enter, from time to time, into sales agreements for the marketing and sale of such products pursuant to which we are obligated to pay commissions to such representatives upon the sale of our products in the relevant territory covered by such agreements by such representatives or, in some cases, by other representatives in such territory.

 

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 $325.8 million as of February 26, 2015, which includes revenues for the period between January 1, 2015 and February 19, 2015, compared to $165.0 million as of February 26, 2014, which included revenues for the period between January 1, 2014 and February 15, 2014.

 

The following is a breakdown of the Product Segment backlog as of February 26, 2015 (dollars in millions): 

 

 

Expected Completion of the Contract

 

Sales Expected to be Recognized in 2015

   

Sales Expected to be Recognized in the years following 2015

   

Expected Until End of Contract

 
                           

Geothermal

2017

    148.7 - 156.9       130.9 - 139.1     $ 282.8  

Recovered Energy

2016

    18.2 - 19.3       3.2 - 4.3       22.5  

Remote Power Units

2016

    7.4 - 7.8       2.3 - 2.7       10.1  

Other

2017

    5.7 - 6.0       4.4 - 4.7       10.4  

Total

     180.0 - 190.0        140.8 - 150.8       325.8  

 

 

 
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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 or system integrators and from engineering or projects management companies.

 

Electricity Segment

 

Competition in the Electricity Segment is particularly marked in the very early stage of either obtaining the rights to the resource for the development of future projects or acquiring a site already in a more advanced stage of development. Once we or other developers obtained such rights or own a power plant, competition is limited. From time to time and in different jurisdictions competing geothermal developers become our customers in the Product Segment.

 

The main companies competing with us in the geothermal sector in the United States are CalEnergy, Calpine Corporation, Terra-Gen Power LLC, Enel Green Power S.p.A and other smaller-sized pure play developers. Outside the United States, in many cases our competitors are companies that gained experience developing geothermal projects in their own countries and are now seeking to take this experience and develop geothermal projects in other countries. The main ones are Chevron Corporation, Energy Development Corporation (EDC) from the Philippines, Mighty River Power (MRP) and Contact Energy Limited from New Zealand, Origin Energy from Australia, Tata Group from India and Enel Green Power from Italy. Additionally, we see competition from small country specific companies. While the geothermal industry is characterized by high barriers to entry, national electric utilities or state-owned oil companies might also enter the market.

 

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 site-specific and base load advantages can allow us to develop competitive projects.

 

Product Segment

 

Our competitors among power plant equipment suppliers are divided into: high enthalpy and low enthalpy competitors. The main high enthalpy competitors are industrial steam turbine manufacturers such as Mitsubishi Hitachi Power Systems, Fuji Electric Co., Ltd. and Toshiba of Japan, GE/Nuovo Pignone brand and Ansaldo Energia of Italy.

 

The low enthalpy competitors are either binary systems manufacturers using the Organic Rankine Cycle such as Fuji Electric Co., Ltd of Japan, Atlas Copco Company, Exergy of Italy, and Mitsubishi Hitachi Power Systems (which acquired Turboden). While we believe that we have a distinct competitive advantage based on our accumulated experience and current worldwide share of installed binary generation capacity (which is in excess of 90%), an increase in competition, which we are currently experiencing, has started to impact our ability to secure new purchase orders from potential customers. The increased competition may also lead to a reduction in the prices that we are able to charge for our binary equipment, which in turn may impact our profitability.

 

In the REG business, our competitors are other Organic Rankine Cycle manufacturers (such as GE and Mitsubishi/Turboden), manufactures that use Kalina technology (such as Geothermal Energy Research & Development Co., Ltd in Japan), as well as other manufacturers of conventional steam turbines.

 

In the remote power unit business, we face competition from Global Thermoelectric, as well as from manufacturers of diesel generator sets and small wind and solar installations with batteries.

 

Currently, none of our competitors compete with us in both the Electricity and the Product Segments.

 

When the proposed project is an EPC project we also compete with other service suppliers, such as project/engineering companies.

 

 
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Customers

 

All of our revenues from the sale of electricity in the year ended December 31, 2014 were derived from fully-contracted energy and/or capacity payments under long-term PPAs with governmental and private utility entities. Southern California Edison, Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy), HELCO, and SCPPA accounted for 13.5%, 16.5%, 8.0% and 3.9% of revenues, respectively, for the year ended December 31, 2014. Based on publicly available information, as of December 31, 2014, the issuer ratings of Southern California Edison, HELCO, Sierra Pacific Power Company, Nevada Power Company, and SCPPA were as set forth below:

 

Issuer

Standard & Poor’s Ratings Services

Moody’s Investors Service Inc.

Southern California Edison

BBB+ (stable outlook)

A2 (stable outlook)

HELCO

BBB- (Watch)

Baa1(stable outlook)

Sierra Pacific Power Company

BBB+ (stable outlook)

Baa1 (stable outlook)

Nevada Power Company

BBB+ (stable outlook)

Baa1 (stable outlook)

SCPPA

A- (Negative outlook)

Aa3 (stable outlook)

Pacific, Gas and Electric

BBB (Negative outlook)

A3 (stable outlook)

 

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 such raw materials are readily available from various suppliers.

 

We use subcontractors for some of the manufacturing for our products components and for construction activities of our power plants, which allows us to expand our construction and development capacity on an as-needed basis. We are not dependent on any one subcontractor and expect to be able to replace any subcontractor, or assume such manufacturing and construction activities of our projects ourselves, without adverse effect to our operations.

 

Employees

 

As of December 31, 2014, we employed 1,095 employees, of which 471 were located in the United States, 515 were located in Israel and 109 were located in other countries. We expect that future growth in the number of our employees will be mainly attributable to the purchase and/or development of new power plants.

 

None of our employees are represented by a labor union, and we have never experienced any labor dispute, strike or work stoppage. We consider our relations with our employees to be satisfactory. We believe our future success will depend on our continuing ability to hire, integrate, and retain qualified personnel.

 

In the United States, we currently do not have employees represented by unions recognized by the company under collective bargaining agreements. However, a union has filed a petition with the National Labor Relations Board (NLRB) in an attempt to organize our employees in our Puna complex in Hawaii. The NLRB ruled that a certification of representative should be issued. The Company appealed the NLRB decision and the matter is currently under litigation in the federal Court of Appeals for the Ninth Circuit in California.

 

We have no collective bargaining agreements with respect to our Israeli employees. However, by order of the Israeli Ministry of Industry, Trade and Labor, 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 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.

 

 
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Insurance

 

We maintain business interruption insurance, casualty insurance, including flood, volcanic eruption and earthquake coverage, and primary and excess liability insurance, control of wells, as well as customary worker’s compensation and automobile, marine transportation insurance and such other commercial insurance, if any, as is generally carried by companies engaged in similar businesses and owning similar properties in the same general areas or as may be required by any of our PPAs, or any lease, financing arrangement, or other contract. To the extent any such casualty insurance covers both us and/or our power plants, and any other person and/or plants, we generally have specifically designated as applicable solely to us and our power plants “all risk” property insurance coverage in an amount based upon the estimated full replacement value of our power plants (provided that earthquake, volcanic eruption and flood coverage may be subject to annual aggregate limits depending on the type and location of the power plant) and business interruption insurance in an amount that also varies from power plant to power plant.

 

We generally purchase insurance policies to cover our exposure to certain political risks involved in operating in developing countries. Political risk insurance policies are generally issued by entities which specialize in such policies, such as MIGA (a member of the World Bank Group), or by private sector providers, such as Lloyd Syndicates, Zurich Emerging Markets and other such companies. To date, all of our political risk insurance contracts are with the Multilateral Investment Guarantee Agency and with Zurich Emerging Markets. Currently we hold such insurance for all of our foreign power plants in operation, and for the Sarulla project, which is under construction. Such insurance policies generally cover, subject to the limitations and restrictions contained therein, approximately 90% of our losses derived from a specified governmental act, such as confiscation, expropriation, riots, and the inability to convert local currency into hard currency and, in certain cases, the breach of agreements with governmental entities.

 

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 the FERC prior to December 21, 1994, and construction of the facility commenced prior to December 31, 1999.

 

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 authority’s implementation of PURPA or (b) not pursuant to another provision of a state regulatory authority’s implementation of PURPA. The practical effect of these regulations is to require owners of Qualifying Facilities that are larger than 20 MW in size to obtain market-based rate authority from FERC if they seek to sell energy or capacity other than pursuant to a contract executed before March 17, 2006 pursuant to a state regulatory authority’s implementation of PURPA or pursuant to a provision of a state regulatory authority’s implementation of PURPA. Until that contract expires, is terminated or is materially modified, a Qualifying Facility, under a PURPA contract executed prior to March 17, 2006, will not be required to file for market based rates.

 

 
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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.

 

We expect that our power plants in the United States 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, the power plants’ existing PPAs will not be affected, but the utilities will not be obligated under PURPA to renew these PPAs or execute new PPAs upon the existing PPAs’ expiration.

 

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 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 the FERC has exclusive jurisdiction over the rates for most wholesale sales of electricity and transmission in interstate commerce. These rates may be based on a cost of service approach or may be determined on a market basis through competitive bidding or negotiation. 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 many provisions of the FPA. If any of the 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 regulations. The application of the FPA and other applicable state regulations to the power plants could require our power plants to comply with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility. Even if a power plant does not lose Qualifying Facility status, if a PPA with a power plant expires, is terminated or is materially modified, the owner of a Qualifying Facility power plant in excess of 20 MW will become subject to rate regulation under the Federal Power Act.

 

If a power plant in the United States 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, the 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, the 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 received from the power plant, either of which would have an adverse effect on our revenues.

 

 
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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. 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 CPUC.

 

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 and permits hazardous materials storage and management permits and pressure vessel operating permits. We are also required to obtain water rights permits in Nevada. In addition to permits, there are various regulatory plans and programs that are required, including risk management plans (federal and state programs) and hazardous materials management plans (in California).

 

 
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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 lead to increases in the time to receive such permits and associated costs of compliance.

 

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 are currently experiencing regulatory delays in obtaining various environmental permits and approvals required for projects in development and construction. These delays may lead to increases in the time and cost to complete these projects. Our operations are designed and conducted to comply with applicable environmental permit and approval requirements. Non-compliance with any such requirements could result in fines and penalties, and could also affect our ability to operate the affected project.

 

Environmental Laws and Regulations

 

Our facilities are subject to a number of environmental laws and regulations relating to development, construction and operation. In the United States, 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, 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 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.

 

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 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).

 

 
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ITEM 1A. RISK FACTORS

  

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.

 

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 68.3% of our total revenues for the year ended December 31, 2014 from the sale of electricity. The cost of operation and maintenance and the operating performance of our subsidiaries’ geothermal power and REG plants may be adversely affected by a variety of factors, including some that are discussed elsewhere in these risk factors and the following:

 

 

regular and unexpected maintenance and replacement expenditures;

 

 

shutdowns due to the breakdown or failure of our equipment or the equipment of the transmission serving utility;

 

 

labor disputes;

 

 

the presence of hazardous materials on our power plant sites;

 

 

continued availability of cooling water supply;

 

 

catastrophic events such as fires, explosions, earthquakes, landslides, floods, releases of hazardous materials, severe weather storms, or similar occurrences affecting our power plants or any of the power purchasers or other third parties providing services to our power plants; and

 

 

the aging of power plants (which may reduce their availability and increase the cost of their maintenance).

 

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. For example, in 2013 we replaced old equipment at the Mammoth complex, which were not manufactured by us. Such major maintenance activities impact both the capacity factor of the affected power plant and its operating costs

 

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. For example, some of Brady’s production wells have cooled significantly due to breakthrough from injection wells. Because geothermal reservoirs are complex geological structures, we can only estimate their geographic area and sustainable output. The viability of geothermal power plants depends on different factors directly related to the geothermal resource (such as the temperature, pressure, storage capacity, transmissivity, and recharge) as well as operational factors relating to the extraction or reinjection of geothermal fluids. For example, at our North Brawley power plant, instability of the sands and clay in the geothermal resource and variability in the chemical composition of the geothermal fluid have all combined to increase our capital expenditures for the plant, as well as our ongoing operating expenses, and have so far prevented the plant from operation at its intended design capacity. In our North Brawley power plant in 2014 we also experienced an uncontrolled flow in one of the production wells that caused to a reduction in generation and increased costs. Our geothermal energy power plants may also suffer an unexpected decline in the capacity of their respective geothermal wells and are exposed to a risk of geothermal reservoirs not being sufficient for sustained generation of the electrical power capacity desired over time.

 

 
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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 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 PPAs, receipt of required governmental permits, obtaining adequate financing, and the timely implementation and satisfactory completion of construction. 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, 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.

 

 
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Currently, we have projects and prospects under exploration, development or construction in the United States, Kenya, Chile, Guatemala, New Zealand, Honduras and Indonesia, 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:

 

 

unanticipated cost increases;

 

 

shortages and inconsistent qualities of equipment, material and labor;

 

 

work stoppages;

 

 

inability to obtain permits and other regulatory matters;

 

 

failure by key contractors and vendors to timely and properly perform, including where we will use equipment manufactured by others;

 

 

failure by key suppliers to provide steam for electricity generation including in the Menengai project in Kenya where the steam will be provided by others.

 

 

inability to secure the required transmission capacity;

 

 

adverse environmental and geological conditions (including inclement weather conditions); and

 

 

our attention to other projects, including those in the solar energy sector.

 

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 with acceptable terms is necessary for the success of our growth strategy. Our attempts to obtain future financings may not be successful or on favorable terms.

 

Market conditions (including those described in the immediately preceding risk factor) 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 (as discussed above), 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 prospects.

 

 
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Our use of joint ventures may limit our flexibility with jointly owned investments.

 

We have entered into an agreement to sell minority equity interests in three 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. 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:

 

 

we could experience an impasse on certain decisions because we do not have sole decision-making authority, which could require us to expend additional resources on resolving such impasses or potential disputes, including litigation or arbitration;

 

 

our joint venture partners could have investment goals that are not consistent with our investment objectives, including the timing, terms and strategies for any investments in the projects that are owned by the joint ventures, which could affect decisions about future capital expenditures, major operational expenditures and retirement of assets, among other things;

 

 

our ability to transfer our interest in a joint venture to a third party may be restricted and the market for our interest may be limited;

 

 

our joint venture partners may be structured differently than us for tax purposes, and this could impact our ability to fully take advantage of federal tax incentives available for renewable energy projects;

 

 

our joint venture partners might become bankrupt, fail to fund their share of required capital contributions or fail to fulfill their obligations as a joint venture partner, which may require us to infuse our own capital into the venture on behalf of the partner despite other competing uses for such capital; and

 

 

our joint venture partners may have competing interests in our markets and investments in companies that compete directly or indirectly with us that could create conflict of interest issues.

  

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 United States, 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 United States, 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:

 

•     changes in government policies or personnel;

 

•     changes in general economic conditions;

 

•     restrictions on currency transfer or convertibility;

 

•     changes in labor relations;

 

•     political instability and civil unrest;

 

•     changes in the local electricity and/or geothermal markets;

 

•     breach or repudiation of important contractual undertakings by governmental entities; and

 

•     expropriation and confiscation of assets and facilities.

 

 
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In particular, in regards to our Electricity Segment, in Guatemala the electricity sector was partially privatized, and it is currently unclear whether further privatization will occur in the future. Such developments may affect our Amatitlan and Zunil power plants if, for example, they result in changes to the prevailing tariff regime or in the identity and creditworthiness of our power purchasers. In Kenya, recent sentiment suggests increased opposition to the presence of foreign investors generally, including in the electricity sector. Any break-up and potential privatization of KPLC may adversely affect our Olkaria III complex. Although we generally obtain political risk insurance in connection with our foreign power plants, such political risk insurance does not mitigate all of the above-mentioned risks. In addition, insurance proceeds received pursuant to our political risk insurance policies, where applicable, may not be adequate to cover all losses sustained as a result of any covered risks and may at times be pledged in favor of the power plant lenders as collateral. Also, insurance may not be available in the future with the scope of coverage and in amounts of coverage adequate to insure against such risks and disturbances. In regards to our Product segment, since we primarily engage in sales in those markets where there is a geothermal reservoir, any such change might adversely affect geothermal developers in those markets and, subsequently, the ability of such developers to purchase our products. Any or all of these changes could materially 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 revenue 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 revenue is attributed to our electricity revenues derived from power purchasers under the relevant PPAs. There is a risk that any one or more of the power purchasers may not fulfill their respective payment obligations under their PPAs. If any of the power purchasers fails to meet its payment obligations under its PPAs, it could materially and adversely affect our business, financial condition, future results and cash flow.

 

Seasonal variations may cause significant 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 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. Some of our other power plants may experience reduced generation during warm periods due to the lower heat differential between the geothermal fluid and the ambient surroundings. Such seasonal variations could materially and adversely affect our business, financial condition, future results and cash flow. If our operating results fall below the public’s or analysts’ expectations in some future period or periods, the market price of our common stock will likely fall in such period or periods.

 

Pursuant to the terms of some of our PPAs with investor-owned electric utilities and public-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.

 

Under the PPAs of our Burdette (Galena 1), Desert Peak 2, Galena 2, Galena 3, Jersey Valley, McGinness Hills, Tuscarora North Brawley and Don A. Campbell power plants, we may be required to make payments to the relevant power purchaser in an amount equal to such purchaser’s replacement costs for renewable energy relating to any shortfall amount of renewable energy that we do not provide as required under the PPA and which such power purchaser is forced to obtain from an alternate source. Also, under the PPAs of our Zunil and Puna power plants, we may be required to pay penalties payments to the relevant power purchaser in an amount agreed upon if we have shortfall amounts of energy that we do not provide as required under the PPA. All of these plants were in commercial operation in 2014, and to date, the shortfall amount has not been material. In addition, we may be required to make payments to the relevant power purchaser in an amount equal to its replacement costs relating to any renewable energy credits we do not provide as required under the relevant PPA. We may be subject to certain penalties, and we may also be required to pay liquidated damages if certain minimum performance requirements are not met under certain of our PPAs. With respect to the Brady PPA, we may also be required to pay liquidated damages of approximately $1.5 million (increased by the percent change in GNP deflator) to our power purchaser if the relevant power plant does not maintain availability of at least 85% during applicable peak periods. Any or all of these could materially and adversely affect our business, financial condition, future results and cash flow.

 

 
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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 a number of the PPAs for our power plants in California, the price that Southern California Edison pays is based upon its SRAC, which are the incremental costs that it would have incurred had it generated the relevant electrical energy itself or purchased such energy from others. Under settlement agreements between Southern California Edison and a number of power generators in California that are Qualifying Facilities, including our subsidiaries, the energy price component payable by Southern California Edison was fixed through April 2012, but since then and going forward it will be based on Southern California Edison’s SRAC, as determined by the CPUC. These SRAC may vary substantially on a monthly basis, and are expected to be based primarily on natural gas prices for gas delivered to California as well as other factors. The levels of SRAC prices paid by Southern California Edison may decline following the expiration date of the settlement agreements, which in turn would reduce our power plant revenues derived from Southern California Edison under our PPAs and could materially and adversely affect our business, financial condition, future results and cash flow.

 

In December 2010, a global settlement (Global Settlement) relating primarily to the purchase and payment obligations of investor-owned utilities to Qualifying Facilities was approved by the CPUC and became effective on November 23, 2011. Under the terms of the Global Settlement, existing Qualifying Facilities with “Legacy PPAs” (meaning any PPA that was in effect at the time the Global Settlement went into effect) had the option to choose to enter into a “Legacy PPA Amendment” within 180 days of the effectiveness of the Global Settlement. The Legacy PPA Amendment allowed a Qualifying Facility to choose a pricing methodology option going forward from the “pricing effective date”, which in our case was the end of the fixed rate period that terminated April 2012 under a prior settlement agreement with Southern California Edison until December 31, 2014, after which the SRAC will be tied only to a formula with energy market heat rates. The pricing options that we chose for our PPAs were as follows:

 

 

In the case of our Ormesa complex and Heber complex PPAs we switched to a new SRAC methodology, which includes fixed rates, declining heat rates, a variable O&M component, an adjustment based on location, and a price adjustment if GHG costs are imposed on the facility, all until December 31, 2014, after which the SRAC will be tied only to a formula with energy market heat rates; and

 

 

In the case of our Mammoth G2 power plant PPA we switched to the same formula specified in (1) above but with somewhat higher heat rates, no GHG cost adder and no location adjustment (for renewable resources).

 

The Global Settlement further provides that after July 1, 2015 if the term of a Qualifying Facility’s Legacy PPA expires, the investor-owned utilities would have no obligation to purchase power from the Qualifying Facility if the Qualifying Facility has a generating capacity in excess of 20 MW. Qualifying Facilities below 20 MW will be entitled to a new standard offer PPA, with SRAC pricing and capacity payments as determined from time to time by the CPUC. The joint parties to the Global Settlement agreed that the utilities can go to FERC to obtain a waiver of the mandatory purchase obligation under PURPA for Qualifying Facilities above 20 MW and FERC has granted such waiver for these California utilities. Our existing PPAs with California investor-owned utilities are not affected by this waiver.

 

 
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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 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. 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 entitled "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", the utilities in the other regions in which our domestic power plants operate were to be relieved of the mandatory purchase obligation, they would not be required to purchase energy from the power plant in the region under Federal law upon termination of the existing PPA or with respect to new power plants, which could materially and adversely affect our business, financial condition, future results and cash flow.

  

Our financial performance is significantly dependent on the successful operation of our power plants, which is subject to 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.

 

 
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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 United States, 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 not be able to successfully integrate companies which we 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:

 

 

failure of the acquired companies to achieve the results we expect;