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, 2004


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

Commission file number: 333-121655

ORMAT FUNDING CORP.

(Exact name of registrant as specified in its charter)

980 Greg Street, Sparks, Nevada 89431
(Address of principal executive offices)

Registrant's telephone number, including area code: (775) 356-9029
Securities to be registered pursuant to Section 12(b) of the Act: None
Securities to be registered pursuant to Section 12(g) of the Act: None

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 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 an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act). Yes No

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter. None.

As of March 15, 2005, the registrant had 500 shares of its common stock, $1.00 par value, outstanding (all shares held by an affiliate of the registrant).

Documents Incorporated by Reference: None

Ormat Funding Corp. is an indirect wholly owned subsidiary of Ormat Technologies, Inc. and meets the conditions set for this General Instruction I (1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.

ORMAT FUNDING CORP.

FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2004

TABLE OF CONTENTS


		Page No.
PART I			5
Item 1.	Business		5
Item 2.	Properties		20
Item 3.	Legal Proceedings		20
Item 4.	Submission of Matters to a Vote of Security Holders		22
PART II			23
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		23
Item 6	Selected Financial Data		23
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations		25
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		53
Item 8.	Financial Statements and Supplementary Data		54
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		101
Item 9A.	Disclosure Controls and Procedures		101
Item 9B.	Other Information		101
PART III			102
Item 10.	Directors and Executive Officers of the Registrant		102
Item 11.	Executive Compensation		103
Item 12.	Security Ownership and Certain Beneficial Owners and Management		103
Item 13.	Certain Relationships and Related Transactions		103
Item 14.	Principal Accountant Fees and Services		105
PART IV			106
Item 15.	Exhibits and Financial Statement Schedules		106
SIGNATURES			118

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 annual 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, 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. For additional factors that could affect the validity of our forward-looking statements, you should read "Management's Discussion and Analyses of Financial Condition and Results of Operations", "Risk Factors" contained in Part II, Item 7 of this annual report and the "Notes to Financial Statements" contained in Part II, Item 8 of this annual report. 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. 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 and risks discussed in this annual report;


	•	operating risks, including equipment failures and the amounts and timing of revenues and expenses;


	•	geothermal resource risk (such as the heat content of the reservoir, useful life and geological formation);


	•	environmental constraints on operations and environmental liabilities arising out of past or present operations;


	•	project delays or cancellations;


	•	financial market conditions and the results of financing efforts;


	•	political, legal, regulatory, governmental, administrative and economic conditions and developments in the United States;


	•	the enforceability of the long-term power purchase agreements for our projects;


	•	contract counterparty risk;


	•	weather and other natural phenomena;


	•	the impact of recent and future federal and state regulatory proceedings and changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry and incentives for the production of renewable energy, changes in environmental and other laws and regulations to which our company is subject, as well as changes in the application of existing laws and regulations;


	•	current and future litigation;


	•	competition from other similar geothermal energy projects, including any such new geothermal energy projects developed in the future, and from alternative electricity producing technologies;


	•	the effect of and changes in economic conditions in the areas in which we operate;


	•	market or business conditions and fluctuations in demand for energy or capacity in the markets in which we operate; and


	•	the direct or indirect impact on our company's business resulting from terrorist incidents or responses to such incidents, including the effect on the availability of and premiums on insurance.

PART I

ITEM 1. BUSINESS

Certain Definitions

Unless the context otherwise requires, all references in this annual report to "Ormat Funding" refer to Ormat Funding Corp. and not to any of its subsidiaries or affiliates; "Ormat," "we," "our," "ours" and "us" refer to Ormat Funding and its subsidiaries on a consolidated basis; "Ormat Nevada" refers to Ormat Nevada Inc., our direct parent company; "Ormat Technologies" and "OTec" refers to Ormat Technologies, Inc., the parent company of Ormat Nevada; and "Ormat Industries" refers to Ormat Industries Ltd., our ultimate parent company. Unless the context otherwise requires, "plants" refers to the various power generating plants owned and/or operated by our subsidiaries or the entities in which they hold equity interests, and "units" refers to particular power generating units at those plants. We refer to a group of plants and the geothermal resource associated with them in a certain geographic area as a "project." The "Senior Secured Notes" refers to our 8¼% Senior Secured Notes due 2020 that were sold in February 2004.

Overview of Ormat Funding

Ormat Funding was formed in December 2001 to develop, construct, own, and acquire through certain direct and indirect subsidiaries geothermal power projects in the United States. As of December 31, 2004, we wholly-owned four geothermal power projects with 168 megawatts ("MW") of gross electrical generating capacity and 102 megawatts of net electrical generating capacity, and we own a 50% interest in a fifth geothermal power project with an additional 35 megawatts of gross electrical generating capacity and 25 megawatts of net electrical generating capacity.

Overview of Our Parent Companies

We are wholly-owned by Ormat Nevada, which is engaged in the ownership, development, construction and operation of geothermal power plants in the United States. Ormat Nevada operates and maintains each of our projects pursuant to an operations and maintenance agreement with each of the project companies. In December 2003 and January 2004, Ormat Nevada and its affiliates purchased for $252.5 million all of the geothermal assets of Covanta Energy Corporation and related assets, which consisted of the Heber plant and SIGC plant in Imperial County, California and a 50% interest in the Mammoth project. Based on publicly available industry data, Ormat Nevada is a leading geothermal power producer in the United States, with over 230 MW of net electrical generating capacity located in the western United States. Ormat Nevada and all of its subsidiaries are United States companies. Ormat Nevada is a wholly-owned subsidiary of Ormat Technologies, or "OTec", which in turn is a subsidiary of Ormat Industries.

Ormat Industries, which is based in Israel, is an international power systems company whose predecessor, Ormat Turbines Ltd., was founded in 1965 by Lucien and Yehudit Bronicki for the principal purpose of developing equipment for the production of clean, renewable energy. Lucien and Yehudit Bronicki, through Bronicki Investment, Ltd. continue to control approximately 34.45% of the outstanding shares of Ormat Industries. Ormat Industries and its subsidiaries have developed geothermal power plants, remote power units, industrial recovered energy systems and solar energy plants worldwide. At December 31, 2004, Ormat Industries and its subsidiaries had 677 employees worldwide. Ormat Industries is listed on the Tel Aviv Stock Exchange under the symbol "ORMT." Ormat Industries and its subsidiaries have supplied, developed, constructed or rehabilitated gross installed capacity of approximately 700 MW of geothermal power plants (or over 700MW including recovered energy power plants) in 22 countries, constituting approximately 9% of geothermal installed capacity worldwide. Ormat Industries' geothermal power plants range in size from 300 kW to over 130 MW and employ binary, flash steam, dry steam and steam/brine combined cycle technologies.

Ormat Industries formed OTec in 1994 for the purpose of investing and holding ownership interests in power plants owned by OTec and third parties. OTec has served as the holding company

for all of Ormat Industries' geothermal power projects. OTec provides us with various accounting, legal, financial, developmental, operational, management and other services and assistance of the type customarily furnished by a parent corporation to its consolidated subsidiaries. OTec is reimbursed indirectly by us, through payments to Ormat Nevada under the operations and maintenance agreements for costs and expenses incurred by us and our subsidiaries in connection with the provision of such services. Effective as of July 1, 2004, Ormat Industries sold to OTec its business relating to the manufacturing and sale of energy-related services, which is based in Israel. As a result of this sale, OTec now holds all of Ormat Industries' power generation and products business. On November 16, 2004, OTec sold 7,187,500 shares of its common stock, par value $0.001 per share, in an initial public offering. The common shares are traded on the New York Stock Exchange under the symbol "ORA."

Ormat Nevada and Ormat Funding have available to them the extensive experience of the Ormat Industries group of companies, including OTec, in developing and operating power projects. The key members of our senior management and engineers of Ormat Nevada, OTec and Ormat Industries have extensive experience developing and operating technologies and power projects and an average of over 20 years of power industry experience.

Corporate Structure


*	The remaining 22.8% of the common stock of OTec was sold to the public pursuant to an initial public offering in November 2004.


**	Constellation Energy Group is not an affiliate of ours and holds its 50% interest through certain of its subsidiaries.

Geothermal Energy

General

Our projects all produce geothermal energy. Geothermal energy is a clean, renewable and generally sustainable energy source that, because it does not utilize combustion in the production of electricity, releases significantly lower levels of emissions, principally steam, than result from energy generation based on the burning of fossil fuels. Geothermal energy is derived from the natural heat of

the earth when water comes sufficiently close to hot molten 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. The energy necessary to operate a geothermal power plant is typically obtained from several such wells, which are drilled using established technology that is in some respects similar to that employed in the oil and gas industry. Geothermal production wells are normally located within approximately one to two miles of the power plant as geothermal fluids cannot be transported economically over longer distances due to heat loss and redistributive costs. 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 after the withdrawal of geothermal fluids as long as the wellfield is properly operated. Geothermal energy projects typically have higher capital costs (primarily as a result of wellfield development) but tend to have significantly lower variable costs, principally consisting of maintenance capital expenditures, than fossil fuel-fired power plants that require ongoing fuel expenses.

Each of the areas in which the projects are located has been designated as a Known Geothermal Resource Area, which we refer to as a "KGRA," by the BLM pursuant to the Geothermal Steam Act of 1970. Areas are designated as KGRAs when the BLM determines that a commercially viable geothermal resource is likely to exist. There are over 100 KGRAs in the United States, which are predominantly located in the western states in tectonically active regions.

Geothermal Power Plant Technologies

Our geothermal power plants employ binary systems and flash design.

Binary System

In a 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 heat exchanger, which heats a secondary working fluid which has a low boiling point. This is typically an organic fluid such as isopentane or isobutane, which is vaporized and is used to drive the turbine. The organic fluid is then condensed in a condenser which may be cooled by air or by water from a cooling tower. The condensed fluid is then recycled back to the heat exchanger, closing the cycle within the sealed system. The cooled geothermal fluid is then reinjected back into the reservoir. The binary technology is depicted in the graphic below.

Flash Design System

In a 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 in the plant, where any remaining water droplets are removed. This produces a stream of dry steam, which drives a 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 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 condensate is used to provide make-up water for the cooling tower. The hot brine remaining after separation of steam is injected back into the geothermal resource through a series of injection wells. The flash technology is depicted in the graphic below.

In some instances, the wells directly produce dry steam (the flashing occurring under ground). In such cases, the steam is fed directly to the steam turbine and the rest of the system is similar to the flash power plant described above.

Operating Strategy

We seek to maximize the cash flow from each of our projects through active management of the projects' cost structure and prudent use of the geothermal resources that power the projects. In particular, we intend to:

•

Increase project efficiency by carefully maintaining our existing plants and geothermal resources and enhancing projects after careful cost/benefit analysis. For example, we and our partner in the Mammoth project, Constellation Energy Group, are planning to add a pipeline and certain other equipment at the Mammoth project with the intention of increasing output by 30,500 MWh per year. We and Constellation Energy Group are currently evaluating a change to this plan, including an increase in the capital expenditure as well as performance.


•	Maximize revenues through expansion of projects and incremental revenue opportunities. For example, we have recently begun to enter bids to sell renewal energy credits to utilities.


•	Realize cost savings by leveraging the experience of our parent company, Ormat Nevada. We believe that we will benefit from Ormat Nevada's improved bargaining power with third party suppliers as it continues to own and operate a growing number of projects beyond ours.

Our Projects

Projects in Operation

The tables below summarize key information relating to our projects that are in operation, under construction and/or subject to enhancement:

Project

Location

Ownership

Commercial
Operation Date

Generating
Capacity in
MW ⁽¹⁾

Power
Purchaser

Contract
Expiration

Ormesa

East Mesa,
California

100

1986 / 1987

47 MW

Southern California Edison

2017 / 2018

Steamboat 2/3

Steamboat, Nevada

100

1992

29 MW

Sierra Pacific Power Company

2022

Mammoth

Mammoth Lakes, California

1984 / 1990

25 MW

Southern California Edison

2015 / 2020

Brady

Churchill County, Nevada

100

1985 / 1992

20 MW

Sierra Pacific Power Company

2022

Steamboat 1/1A

Steamboat, Nevada

100

1986 / 1988

5 MW

Sierra Pacific Power Company

2006 / 2018

Projects under Enhancement and Construction

Project

Location

Ownership

Commercial
Operation Date

Net
Generating
Capacity

Power
Purchaser

Contract
Expiration

Galena⁽²⁾

Steamboat Hills, Nevada

100

2005⁽³⁾

13 MW⁽⁴⁾

Sierra Pacific Power Company

N/A⁽⁵⁾

Ormesa

East Mesa, California

100

2006

10 MW⁽⁸⁾

N/A

Mammoth⁽⁶⁾

Mammoth Lakes, California

2006

4 MW⁽⁷⁾

N/A

⁽¹⁾

References to generating capacity refer to the net amount of electrical energy available for sale to the power purchaser. In the case of projects under construction or enhancement, references to generating capacity refer to the net amount of electrical energy that we expect will be available for sale to the relevant power purchasers. This column represents the net generating capacity of the project, not our net ownership in such generating capacity. Such net generating capacity is based on operational data for the 12-month period beginning January 1, 2004 through and including December 31, 2004.


⁽²⁾	After the enhancement of the Steamboat 1/1A project is completed, we will rename the Steamboat 1/1A project as the Galena project.


⁽³⁾	Projected Fourth quarter of 2005.


⁽⁴⁾	Incremental megawatts to the Steamboat complex.


⁽⁵⁾	The power purchase agreement will expire 20 years from the commercial operation date.


⁽⁶⁾	This project is in its early engineering stage.


⁽⁷⁾	We expect that the enhancement will increase the total output of the project by 4 MW.


⁽⁸⁾	We expect to sell an additional 10 MW. We are currently negotiating with a third party for the sale of this additional output pursuant a new long term power purchase agreement.

All of our revenues are derived from fully-contracted energy and/or capacity payments under long-term power purchase agreements with two utility companies. For the year ended December 31, 2004, we generated 54% of our revenues from Southern California Edison and 46% of our revenues from Sierra Pacific Power Company

Qualifying Facility. Our projects in the United States are "Qualifying Facilities" under the Public Utility Regulatory Policies Act of 1978, as amended, which we refer to as PURPA, which provides for certain beneficial Federal regulatory treatment. As a result, we are exempt from various regulations under the Federal Power Act of 1920, as amended, which we refer to as the FPA.

Operations, Maintenance and Administrative Services. Ormat Nevada provides operations and maintenance services and administrative services for the all our projects pursuant to operations and maintenance agreements between each of the owners of the projects and Ormat Nevada. These services include operations and maintenance of the plants, wells and gathering systems, obtaining parts and supplies, preparing reports for third parties, enforcing all warranties and claims and maintaining compliance with permits, licensing and insurance standards. In connection with the operations and maintenance agreements, we paid Ormat Nevada $28.7 million in the year ended December 31, 2004.

The Steamboat Complex

Steamboat 1/1a Project

General. ORNI 7 acquired 100% of the Steamboat 1/1A project on June 30, 2003. The Steamboat 1/1A project is located in Steamboat Hills, Washoe County, Nevada, approximately nine miles south of Reno, Nevada. The Steamboat 1 plant commenced commercial operations in 1986 and the Steamboat 1A plant commenced commercial operations in 1988. The Steamboat 1/1A project has a gross generating capacity of 10.0 MW and a power purchase agreement nameplate of 7.0 MW, and had an average generation of 5.5 MW and an availability factor of 99.8% for the year ended December 31, 2004.

Project Ownership. We own all of the ownership interests in ORNI 7, which owns all of the ownership interests of Steamboat Geothermal. Steamboat Geothermal owns 100% of the Steamboat 1/1A project. The project was refinanced with the proceeds from the issuance of our Senior Secured Notes. The Senior Secured Notes are collateralized by all of the assets of the Steamboat 1/1A project (and any and all proceeds arising therefrom) and Steamboat Geothermal LLC has, jointly and severally with our other subsidiaries, fully and unconditionally guaranteed our obligations under the Senior Secured Notes. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for further description of collateralization of the Senior Secured Notes.

Production Process. The Steamboat 1/1A project utilizes a binary system.

Sale of Power. The Steamboat 1/1A project sells its net electrical output to Sierra Pacific Power Company under two separate power purchase agreements. These power purchase agreements are similar to each other. The power purchase agreement with respect to the Steamboat 1 plant expires in 2006 unless the parties agree to any extensions. The power purchase agreement with respect to the Steamboat 1A plant expires in 2018 unless the parties agree to any extensions. We currently receive rates under both power purchase agreements based on the monthly average of the California-Oregon Border power market pricing, which is Sierra Pacific Power Company's adopted short-run avoided cost basis.

Transmission. Power is delivered to Sierra Pacific Power Company at the Steamboat 1/1A project.

Operations, Maintenance and Administrative Services. Ormat Nevada provides operations and maintenance services and administrative services for the Steamboat 1/1A project pursuant to an

operations and maintenance agreement. These services include operations and maintenance of the Steamboat 1/1A project, wells and gathering and reinjection systems, obtaining parts and supplies, preparing reports for third parties, enforcing all warranties and claims and maintaining compliance with permits, licensing and insurance standards.

Geothermal Resources. Steamboat Geothermal controls certain rights to geothermal fluids in the Steamboat KGRA through a geothermal lease with Sierra Pacific Power Company. In general, the term of the geothermal resource lease with Sierra Pacific Power Company will continue in effect as long as power is being produced from the leasehold and royalties are being paid. We believe that the Steamboat 1/1A project has rights to all of the geothermal resources necessary to operate the Steamboat 1/1A project as currently planned, although we anticipate revising this contract as described below under "—The Galena Project."

Qualifying Facility. Certain geothermal power generating projects in the United States are eligible to be Qualifying Facilities under the FPA as amended by PURPA, which provides for certain beneficial Federal regulatory treatment. The Steamboat 1/1A project is a Qualifying Facility and is eligible for the regulatory exemptions from the FPA, certain state laws and regulations, and PUHCA set forth in 18 C.F.R. Section 292, Subpart F.

The Galena Project. We are using approximately $25.8 million of the proceeds from the sale of our Senior Secured Notes to replace the existing equipment at the Steamboat 1/1A project with current Ormat technology, which, upon completion, will optimize the use of available geothermal resources. Additional costs of construction in the amount of $2 million will be funded out of available cash flow. On August 2, 2004, our subsidiary, ORNI 7 LLC, and Ormat Nevada entered into an engineering, procurement and construction agreement pursuant to which Ormat Nevada will design, engineer and construct the Galena project.

We will also augment the operation of the Steamboat 1/1A project with additional geothermal resources from the Steamboat 2/3 project's leases. After this upgrade, we will rename the Steamboat 1/1A project as the Galena project. We expect that the enhancement will increase the total output of the Steamboat complex by 13 MW. We believe that this upgrade will allow the Galena project to obtain an average generation of 20 MW. Our project subsidiary is coordinating the transition from the Steamboat 1/1A project to the Galena project with Sierra Pacific Power Company.

We anticipate that the Galena project will be complete and that the Galena project will achieve commercial operations at the end of 2005. The project will sell its electricity output and transfer its renewable energy credit to Sierra Pacific Power Company pursuant to a power purchase agreement entered into on June 29, 2004 and approved by the Public Utilities Commission of Nevada on October 14, 2004, which has a 20 year term commencing on the January1 following the commencement of commercial operations. We will receive energy payments under this power purchase agreement. The price ORNI 7 will receive under the agreement for power produced is $0.052/kWh with annual escalations.

Steamboat 2/3 Project

General. The Steamboat 2/3 project is located in Steamboat Hills, Washoe County, Nevada, approximately nine miles south of Reno, Nevada and near the Steamboat 1/1A project. The Steamboat 2/3 project is comprised of two plants and commenced commercial operations in 1992. The Steamboat 2/3 project utilizes a binary system and has a gross generating capacity of 32.0 MW and a power purchase agreement nameplate of 24.0 MW, and had an average generation of 28.6 MW and an availability factor of 99.9% for the year ended December 31, 2004.

Project Ownership. We own all of the ownership interests in ORNI 7, which owns all of the ownership interests of Steamboat Development. Steamboat Development owns 100% of the Steamboat 2/3 project. The project was acquired in February 2004 using internally generated cash and proceeds from the issuance of our Senior Secured Notes. The Senior Secured Notes are collateralized by all of the assets of the Steamboat 2/3 project (and any and all proceeds arising therefrom) and Steamboat Development has, jointly and severally with our other subsidiaries, fully and

unconditionally guaranteed our obligations under the Senior Secured Notes. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for further description of collateralization of the Senior Secured Notes.

Production Process. The Steamboat 2/3 project uses a binary system similar to that used at the Steamboat 1/1A project with a different geothermal fluid.

Sale of Power. The Steamboat 2/3 project sells its net electrical output to Sierra Pacific Power Company under two separate power purchase agreements. These power purchase agreements are similar to each other. The term of both power purchase agreements expires in 2022. The energy payment base rate for the power purchase agreement with respect to the Steamboat 2 plant is $0.02425/kWh. The energy payment base rate for the power purchase agreement with respect to the Steamboat 3 plant is $0.025/kWh. The energy payments under both power purchase agreements are increased every year by 4.12% through 2007 and by 3% per year through the end of the term. The current energy payment for the Steamboat 2 plant is $0.0363/kWh and for the Steamboat 3 plant is $0.03595/kWh. The capacity rate under both power purchase agreements is $19.04/kW month until December 2007, when it changes to $14.00/kW month.

Transmission. Power is delivered to Sierra Pacific Power Company at the Steamboat 2/3 project.

Operations, Maintenance and Administrative Services. Ormat Nevada provides operations and maintenance services and administrative services for the Steamboat 2/3 project pursuant to an operations and maintenance agreement. These services include operations and maintenance of the Steamboat 2/3 project, wells and gathering and reinjection systems, obtaining parts and supplies, preparing reports for third parties, enforcing all warranties and claims and maintaining compliance with permits, licensing and insurance standards.

Geothermal Resources. Steamboat Development controls certain rights to geothermal fluids in the Steamboat KGRA through a lease and a sublease of geothermal rights. We believe that the Steamboat 2/3 project has all of the geothermal resources necessary to operate the Steamboat 2/3 project as currently planned.

Qualifying Facility. The Steamboat 2/3 project is a Qualifying Facility and is eligible for the regulatory exemptions from the FPA, certain state laws and regulations, and PUHCA set forth in 18 C.F.R. Section 292, Subpart F.

The Mammoth Project

General. Ormat Nevada acquired a 50% interest in the Mammoth project on December 18, 2003 and transferred its interest in the project to us on January 30, 2004. The Mammoth project is located in Mammoth Lakes, Mono County, California. The Mammoth project is comprised of three plants, G1, G2 and G3. The G1 plant commenced commercial operations in 1985 and the G2 and G3 plants commenced commercial operations in 1990. The Mammoth project utilizes a binary system and has a gross generating capacity of 35.0 MW and a power purchase agreement nameplate of 32.0 MW, and had an average generation of 24.9 MW and an availability factor of 99.6% for the year ended December 31, 2004.

Project Ownership. We own all of the ownership interests in OrMammoth. OrMammoth owns a 49% general partnership interest and a 1% limited partnership interest in Mammoth-Pacific, L.P. The remaining 50% partnership interest in Mammoth-Pacific, L.P. is owned by subsidiaries of Constellation Energy Group, a publicly traded energy company. Mammoth-Pacific, L.P. owns 100% of the Mammoth project. The project was refinanced with the proceeds from the issuance of our Senior Secured Notes. The Senior Secured Notes are collateralized by a pledge of our 50% ownership interest in Mammoth Pacific, L.P. and OrMammoth has, jointly and severally with our other subsidiaries, fully and unconditionally guaranteed our obligations under the Senior Secured Notes. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for further description of collateralization of the Senior Secured Notes.

Production Process. The Mammoth project uses a binary system similar to that used at the Steamboat 2/3 project.

Sale of Power. The Mammoth project sells its net electrical output to Southern California Edison under three separate power purchase agreements. These power purchase agreements are similar to each other. The power purchase agreement with respect to the G1 plant expires in February 2015 and the power purchase agreements with respect to the G2 plant and the G3 plant expire in December 2020. Mammoth-Pacific, L.P. receives a fixed energy payment of $0.0537/kWh through April 2007, and thereafter an energy payment based on Southern California Edison's short-run avoided cost, which we refer to as "SRAC." Mammoth-Pacific, L.P. also receives capacity payments under the power purchase agreements. The G3 plant power purchase agreement further provides for a bonus when the plant capacity factor exceeds 80%.

Transmission. Electric power from the Mammoth project is delivered to Southern California Edison's Casa Diablo substation located in Bishop, California via a half mile, 33kV line owned, operated and maintained by Southern California Edison.

Operations, Maintenance and Administrative Services. Operating and maintenance services for the Mammoth project are provided by Ormat Nevada under a plant operating services agreement.

Geothermal Resources. Mammoth-Pacific, L.P. controls certain rights to geothermal fluids in the Mammoth Lakes KGRA through certain leases with the BLM and Magma Power Company. Mammoth-Pacific, L.P. has entered into long-term agreements with the BLM, Magma Power Company and other third parties to obtain the necessary surface rights and geothermal resource rights necessary to operate the Mammoth project. Mammoth-Pacific, L.P. planned to commence a $5 million enhancement program of the Mammoth project, consisting primarily of drilling activities, which we believe will result in an increase in the output of the project by 4 MW and is expected to be completed by 2006. Mammoth is currently evaluating a change to that program that may increase the cost up to a total of approximately $7.5 million. A substantial portion of the funds required for such enhancement have been earmarked by us and our partners for such enhancement program. We believe that after completing this enhancement, the Mammoth project will have the geothermal resources necessary to operate the Mammoth project as currently planned.

Qualifying Facility. The Mammoth project is a Qualifying Facility and is eligible for the regulatory exemptions from the FPA, certain state laws and regulations, and PUHCA set forth in 18 C.F.R. Section 292, Subpart F.

The Ormesa Project

General. We acquired 100% of the Ormesa project on April 15, 2002. The Ormesa project is located in East Mesa, Imperial County, California, approximately 13 miles north of the Mexican border. The Ormesa project is comprised of six plants, OG I, OG IE, OG IH, OG II, GEM 2 and GEM 3. The various OG I plants commenced commercial operations in 1987-1989 and the OG II plant commenced commercial operations in 1988. GEM 2 and GEM 3 commenced commercial operations in April 1989. The OG I plants have a gross generating capacity of 41.0 MW and a power purchase agreement nameplate of 38.0 MW, and had an average generation of 33.1.MW and an availability factor of 97.6% for the year ended December 31, 2004. The OG II plant has a gross generating capacity of 19.0 MW and a power purchase agreement nameplate of 18.5 MW, and had an average generation of 13.9 MW and an availability factor of 98.1% in 2004. The GEM 2 and GEM 3 plants have a gross generating capacity of 34.0 but electricity generated by the two plants is not sold under a power purchase agreement because their power is used to provide auxiliary power for wellfield operations at the Ormesa project.

Project Ownership. We own all of the ownership interests of Ormesa, which owns 100% of the Ormesa project. The project was initially refinanced with project finance debt from United Capital and was refinanced again with the proceeds from the issuance of our Senior Secured Notes. The Senior Secured Notes are collateralized by all of the assets of the Ormesa project (and any and all proceeds arising therefrom) and Ormesa has, jointly and severally with our other subsidiaries, fully and unconditionally guaranteed our obligations under the Senior Secured Notes. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for further description of collateralization of the Senior Secured Notes.

Production Process. The OG I plants and the OG II plant at the Ormesa project use a binary system similar to that used at the Steamboat 1/1A project. The GEM 2 and GEM 3 plants use a flash design.

Sale of Power. The Ormesa project sells its net electrical output to Southern California Edison under two separate power purchase agreements. These power purchase agreements are similar to each other. The power purchase agreement with respect to the OG I plants expires in October 2017 and the power purchase agreement with respect to the OG II plant expires in March 2018. Ormesa receives a fixed energy payment of $0.0537/kWh through April 30, 2007, and thereafter an energy payment based on Southern California Edison's SRAC. The capacity payment under the OG I power purchase agreement is $170/kW year for 31.5 MW of capacity. The capacity payment under the OG II power purchase agreement is $184/kW year for 15 MW. Both power purchase agreements provide for a bonus when the capacity factor of the plants exceeds 85%. In certain circumstances, Southern California Edison Company or its designee has a right of first refusal to acquire the OG I and OG II plants. The GEM 2 and GEM 3 plants are not currently associated with a power purchase agreement and their power is used to provide auxiliary power for wellfield operations at the Ormesa project.

In connection with the power purchase agreements for the Ormesa project, Southern California Edison Company has expressed its intent not to pay the contract rate for the power supplied under the Ormesa power purchase agreement as a result of the supply by the GEM 2 and GEM 3 plants to the Ormesa project of auxiliary power. We expect to resolve the issue through the sale of the GEM 2 and 3 power that was used to supply auxiliary power to Ormesa to a different offtaker; and we are currently negotiating with a third party the sale of some of the power (10MW) pursuant to a long-term power purchase agreement.

Transmission. Power is delivered to Southern California Edison after transmission over the local transmission system owned by the Imperial Irrigation District pursuant to long-term transmission service agreements and plant connection agreements.

Operations, Maintenance and Administrative Services. Ormat Nevada provides operations and maintenance services and administrative services for the Ormesa project pursuant to an operations and maintenance agreement. These services include operations and maintenance of the Ormesa project, wells and gathering and reinjection systems, obtaining parts and supplies, preparing reports for third parties, enforcing all warranties and claims and maintaining compliance with permits, licensing and insurance standards.

Geothermal Resources. Ormesa controls certain rights to geothermal fluids in the East Mesa KGRA through certain leases with the BLM. Ormesa has entered into long-term agreements with the BLM to obtain the necessary surface rights and geothermal resource rights necessary to operate the Ormesa project. We believe that the Ormesa project has the geothermal resources necessary to operate the Ormesa project as currently planned.

Qualifying Facility. The Ormesa project is a Qualifying Facility and is eligible for the regulatory exemptions from the FPA, certain state laws and regulations, and PUHCA set forth in 18 C.F.R. Section 292, Subpart F.

The Brady Project

General. Ormat Nevada acquired 100% of the Brady project on June 29, 2001 and transferred its interest in the project to us on July 10, 2002. The Brady project is located in Churchill County, Nevada, approximately 50 miles east of Reno, Nevada, and includes the Brady plant and the Desert Peak 1 plant. The Brady plant commenced commercial operations in 1992 and the Desert Peak 1 plant commenced commercial operations in 1985. The Brady project has a gross generating capacity of 32.0 MW and a power purchase agreement nameplate of 21.5 MW, and had a combined average generation of 20.4 MW and an availability factor of 99.3% for the year ended December 31, 2004. The Desert Peak 1 plant is approximately 4.5 miles southeast of the Brady plant. The Brady project was acquired in June 2001 using internal generated cash and was refinanced with a portion of the proceeds from the sale of our Senior Secured Notes.

Project Ownership. We own all of the ownership interests in ORNI 1 and ORNI 2. Each of ORNI 1 and ORNI 2 owns 50% of Brady. Brady is a Nevada general partnership that owns 100% of the Brady project, which includes the Brady plant and the Desert Peak 1 plant. The Brady project was acquired in June 2001 using internal generated cash and was refinanced with a portion of the proceeds from the sale of our Senior Secured Notes. The Senior Secured Notes are collateralized by all of the assets of the Brady project (and any and all proceeds arising therefrom) and Brady has, jointly and severally with our other subsidiaries, fully and unconditionally guaranteed our obligations under the Senior Secured Notes. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for further description of collateralization of the Senior Secured Notes.

Production Process. The Brady plant has historically used a flash design. In August 2002, an additional 6 MW binary unit was added to the Brady plant to generate additional power from the resource before its reinjection. The Desert Peak 1 plant use a flash design.

Sale of Power. The Brady project sells its net electrical output from the Brady plant and Desert Peak 1 plant to Sierra Pacific Power Company under a power purchase agreement that expires in August 2022. The power purchase agreement provides for the sale of energy (up to 188,877,610 kWh per year) and capacity (up to 19.9 MW). Energy payments under the power purchase agreement are based on deliveries during specified winter and summer seasons for on-peak, mid-peak, and off-peak times. Energy rates escalate annually and currently are approximately $.038/kW. Brady receives capacity payments under the power purchase agreement of approximately $220/kW year until August, 2012 and approximately $99.6/kW year thereafter. The capacity payment is based on the lesser of the monthly capacity values specified in the power purchase agreement and the average peak period capacity.

Transmission. Power generated by the Desert Peak 1 plant is transmitted to the Brady plant across a transmission line owned by Brady and is combined with power generated by the Brady plant and delivered to Sierra Pacific Power Company at its substation adjacent to the Brady plant.

Operations, Maintenance and Administrative Services. Ormat Nevada provides operations and maintenance services and administrative services for the Brady project pursuant to an operations and maintenance agreement. These services include operations and maintenance of the Brady project, wells and gathering and reinjection systems, the training or personnel, obtaining parts and supplies, preparing reports for third parties, enforcing all warranties and claims and maintaining compliance with permits, licensing and insurance standards.

Geothermal Resources. Brady controls certain rights to geothermal fluids in the Brady Hot Springs KGRA through certain leases with the BLM and certain subleases with a private sublessor. Brady has entered into long-term agreements with the BLM and the private sublessor to obtain the necessary surface rights and a substantial portion of the geothermal resource rights necessary to operate the Brady plant. Brady also leases a production well from ConAgra in exchange for providing geothermal fluids to ConAgra. Brady acquires geothermal resources for the Desert Peak 1 plant pursuant to the fluid supply agreement with Western States, a subsidiary of Ormat Nevada. On June 1, 2004, Brady purchased certain geothermal and mineral interests and surface rights related to real property located at Brady's Hot Springs from The Burlington Northern and Santa Fe Railway Company. These interests and rights were previously leased by The Burlington Northern and Santa Fe Railway Company to Brady. The purchase of these interests provides us with greater annual cost savings than we realized from leasing the interests and rights to such mineral resources. We believe that Brady has or can obtain the geothermal resources necessary to operate the Brady Project as currently planned.

Qualifying Facility. The Brady project is a Qualifying Facility and is eligible for the regulatory exemptions from the FPA, certain state laws and regulations, and PUHCA set forth in 18 C.F.R. Section 292, Subpart F.

Plant Replacement. We are currently evaluating the replacement of the Desert Peak 1 plant with a new plant that would be more efficient. The new plant may be constructed on the same site as the existing Desert Peak 1 plant. Construction would likely be completed in 2007, at an estimated total project cost of approximately $10 million.

Customers

To date, all of our net revenues have been attributed to payments from Southern California Edison and Sierra Pacific Power Company under their power purchase agreements. In 2004, Southern California Edison accounted for 54% of our revenues and Sierra Pacific Power Company accounted for 46%. We anticipate that for the foreseeable future Southern California Edison and Sierra Pacific Power Company will provide most of our revenues.

Employees

Neither we nor any of our subsidiaries have any employees. Our sole shareholder, Ormat Nevada, provides operation and maintenance for the projects and had approximately 186 employees as of December 31, 2004. Each of the plants is staffed by Ormat Nevada employees. Ormat Nevada has informed us that its relationship with its employees is good.

Insurance

We will maintain or cause to be maintained business interruption insurance, casualty insurance, including flood and earthquake coverage, and primary and excess liability insurance, as well as customary worker's compensation (to the extent we hire any employees) and automobile insurance and such other insurance, if any, as is generally carried by companies engaged in similar businesses and owning similar properties in the same general areas and financed in a similar manner. To the extent any such casualty insurance covers both us and/or our projects, on the one hand, and any other person and/or plants, on the other hand, we will at all times have specifically designated as applicable solely to us and our projects "all risk" property insurance coverage in an amount based upon the estimated full replacement value of our projects (provided that earthquake and flood coverages may be subject to an annual aggregate limit not less than $5.0 million with respect to flood and $10.0 million with respect to earthquake on an annual aggregate basis) and business interruption insurance in an amount of not less than the maximum fixed expenses projected over any four month period during the next twelve months (including, without limitation, debt service expenses). We are prohibited by the indenture governing our Senior Secured Notes from reducing or changing such insurance coverages if an independent insurance consultant determines that such reduction or change would not be reasonable under the circumstances and the insurance coverages sought to be reduced or changed are available on commercially reasonable terms or that another level of coverage greater than that proposed by us is available on commercially reasonable terms (in which case such coverage may be reduced to the higher of such available levels). The indenture governing our Senior Secured Notes requires us to cause the collateral agent thereunder to be named as loss payee and/or as an additional insured, as appropriate; all insurance policies shall provide for at least 30 days' written notice to the collateral agent of a cancellation (except cancellation due to failure to pay premiums, which may be on no less than 10 days' prior written notice to the collateral agent) or reduction in the amount of coverage or of a material change in coverage.

Regulation of the Electric Utility Industry

The following is a summary overview of the electric utility industry and applicable regulations and should not be considered a full statement of all issues pertaining thereto.

PURPA

PURPA, in relevant part, exempts renewable electric generating projects that are "Qualifying Facilities" from various regulations under the FPA. There are two types of Qualifying Facilities: "Qualifying Small Power Production Facilities" and "Qualifying Cogeneration Facilities." Under the FPA as amended by PURPA and the regulations promulgated thereunder, a power production facility is a "Qualifying Small Power Production Facility" if (1) the facility produces no more than 80 MW (on a net capacity basis) or satisfies certain FERC certification and construction dates, (2) the primary energy source of the facility is biomass, waste, renewable resources, geothermal resources or any

combination thereof, and at least 75% of the total energy input is from these sources, and (3) the facility is owned by a person not primarily engaged in the generation or sale of electric power (other than electric power solely from cogeneration facilities or small power production facilities) (i.e., the project company cannot be controlled by, more than 50% of the equity interests of the facility may not be owned by, and more than 50% of the equity benefits cannot be received by an electric utility, an electric utility holding company or a combination thereof or their subsidiaries).

PURPA Qualifying Facilities receive two primary benefits. First, PURPA exempts Qualifying Facilities, such as the projects, from the definition of "electric utility company" under PUHCA, most provisions of the FPA and certain state laws and regulations relating to financial, organization and rate regulation of electric utilities. Second, the regulations promulgated by FERC under PURPA require, in relevant part, that electric utilities (1) purchase energy and capacity made available by Qualifying Facilities, construction of which commenced on or after November 9, 1978, at a rate based on the purchasing utility's full "avoided costs" and (2) sell supplementary, back-up, maintenance and interruptible power to Qualifying Facilities on a just and reasonable and nondiscriminatory basis. FERC's regulations define "avoided costs" as the "incremental costs to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, such utility would generate itself or purchase from another source." Utilities may also purchase power at prices other than avoided cost pursuant to negotiations as provided by FERC's regulations. Under an amendment to PURPA and PURPA regulations, FERC has also provided that utility geothermal small power production facilities (that is, geothermal small power production facilities that would be Qualifying Facilities except that they are owned by a person primarily engaged in the generation or sale of electric energy) are exempt from PUHCA but not state regulation or, if applicable, the FPA.

We expect that the projects will continue to meet all of the criteria required for Qualifying Facilities under PURPA. We have provided self-recertification notices to FERC, including any necessary information required by FERC Form No. 556, regarding the change in ownership of each project, including the changes in ownership of the Mammoth, Steamboat 1/1A and Steamboat 2/3 projects. If any of the projects in which we have an interest lost its Qualifying Facility status or if amendments to PURPA were enacted that substantially reduce the benefits currently afforded Qualifying Facilities, our operations could be adversely affected. Loss of Qualifying Facility status for one of our projects could cause us to become a public utility holding company and subject to other federal and state energy regulation. If we become a holding company, which could be deemed to occur prospectively or retroactively to the date that any of our plants lost its Qualifying Facility status, our other projects could lose Qualifying Facility status because our interests in such projects could be considered to be electric utility holding company interests for purposes of the Qualifying Facility ownership requirements. In addition, a loss of Qualifying Facility status could, depending on the particular power purchase agreement, allow the power purchaser to cease taking and paying for electricity or to seek refunds of past amounts paid and thus could cause the loss of some or all contract revenues or otherwise impair the value of a project. 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 project could be recovered through sales to other purchasers.

In 2003, Congress proposed legislation that, among other provisions, would have had the practical effect of repealing PUHCA and shifting regulatory oversight of holding companies to the FERC, and repealing the mandatory purchase requirements of PURPA. Although the 2003 legislation would not affect existing power purchase agreements for Qualifying Facilities, such legislation or other legislation could (1) repeal or amend PURPA in a manner that substantially reduces the benefits currently afforded Qualifying Facilities, or (2) otherwise make more burdensome the requirements for the projects to maintain their status as Qualifying Facilities. In such event, operations at the projects or compliance with the terms of the power purchase agreements could be adversely affected, and the ability of our subsidiaries' (which are guarantors of our Senior Secured Notes) to make payments under their project notes and guarantees, as well as our financial conditions and ability to service our outstanding debt obligations, could be materially and adversely affected.

PUHCA

The Public Utility Holding Company Act of 1935, as amended, which we refer to as PUHCA, in relevant part, provides that any corporation, partnership or other entity or organized group that owns, controls or holds power to vote 10% or more of the outstanding voting securities of a "public utility company" (which is defined to include an "electric utility company" or a "gas utility company") or of a company that is a "holding company" of a public utility company is subject to registration with the Securities and Exchange Commission and to regulation under PUHCA, unless exempted by SEC rule, regulation or order. An entity may also be deemed to be a holding company if the SEC determines, after providing notice and an opportunity for a hearing, that such entity exercises a controlling influence over the management or policies of any public utility or holding company as to make it necessary or appropriate in the public interest or for the protection of investors or consumers that such entity be regulated as a holding company. Unless an exemption is obtained, PUHCA requires registration for a holding company of a public utility company, and requires a public utility holding company to limit its utility operations to a single integrated utility system and to divest any other operations not functionally related to the operation of the utility system. In addition, a public utility company that is a subsidiary of a registered holding company under PUHCA is subject to financial and organizational regulation, including approval by the SEC of its financing transactions.

Under current federal law, we are not subject to regulation as a holding company under PUHCA and will not be subject to such regulation as long as the plants in which we have an interest are (1) Qualifying Facilities, (2) "Exempt Wholesale Generators" (as defined in PUHCA) or (3) subject to another exemption or waiver, such as status as an electric utility geothermal small power production facility. In order to be a Qualifying Facility, a facility may not be more than 50% owned by one or more electric utility companies or electric utility holding companies. Generally, any geothermal power facility which produces no more than 80 MW of electricity and satisfies the Qualifying Facility ownership requirements is considered a Qualifying Facility.

FPA

Under the FPA, FERC has exclusive rate-making jurisdiction over wholesale sales of electricity and transmission in interstate commerce. These rates may be based on a cost of service approach or may be determined through competitive bidding or negotiation. If a project were to lose its Qualifying Facility status, the rates set forth in its power purchase agreement would have to be filed with FERC and would be subject to review by FERC under the FPA, unless the project is located in Hawaii, Alaska or the parts of Texas that are not deemed to be in interstate commerce. Under FERC policy, the rates under those circumstances could be no higher than the rate or price the relevant power purchaser would have paid for energy had it not been required to purchase from such project under PURPA's mandatory purchase requirements, i.e., such power purchaser's economy energy (incremental) cost during the period of non-compliance with Qualifying Facility requirements, unless the applicable power purchase agreement otherwise provides for alternative rates to apply in the event of such loss of Qualifying Facility status and FERC accepts such alternative rates.

State Regulation

The projects, by virtue of being Qualifying Facilities and because they engage in wholesale sales of electricity to public utilities in California and Nevada, are not subject to rate, financial and organizational regulations applicable to public utilities in those states. The projects each sell or will sell their electrical output to public utilities (either Sierra Pacific Power Company, Nevada Power Company or Southern California Edison) which are regulated by their respective state public utility commission. Sierra Pacific Power Company and Nevada Power Company are regulated by the Nevada PUC ("NPUC"). Southern California Edison and a small portion of Sierra Pacific Power Company in the Lake Tahoe area are regulated by the California Public Utility Commission, which we refer to as CPUC. Since the NPUC and the CPUC regulate the retail rates through which the purchasing utilities recover their payments to our facilities from the retail electric customers of the public electric utilities under their jurisdiction, it is important for the purchasing electric utilities to obtain approval by their

respective public utility commissions of their agreements with our projects. It is also important for the public electric utilities to be allowed continued recovery in their retail electric rates of the cost paid to our projects for electricity.

The NPUC has previously approved the agreements for each of the existing projects located in Nevada and has continuously allowed recovery of the costs of the electricity from those projects in the retail electric rates charged by Sierra Pacific Power Company. The NPUC, pursuant to a delegation of authority from FERC also sets the avoided cost basis for updating the rates in several of the contracts. While we have no reason to believe that the NPUC will not continue to allow such recovery and continue to set the appropriate avoided cost rate, we cannot guarantee a specific avoided cost rate level or recovery in rates by the regulated public utility. The inability to recover the full cost of the electricity from the project by a public utility could adversely impact the ability of the public utility to pay for the electricity from a project, but such adverse treatment is unlikely given the pre-approval of the agreements. Further, we believe that federal law requires the state commissions to permit full recovery of PURPA-based wholesale rates by the purchasing utility, but we are aware of no judicial decisions in California or Nevada upholding this principle.

Recent laws adopted in Nevada require Sierra Pacific Power Company and Nevada Power Company to purchase increasing percentages of their annual electricity requirements from renewable energy systems. The projects located in Nevada, including the proposed Galena project, meet the definition of a renewable energy system in Nevada. The recent renewable energy law in Nevada increases the likelihood that Sierra Pacific Power Company or Nevada Power Company will continue to purchase electricity from the projects. New renewable projects, such as the Galena project, have the sale of their qualifying renewable energy measured in the form of Renewable Energy Credits. Both Sierra Pacific Power Company and Nevada Power Company are required to obtain an increasing amount of such Renewable Energy Credits. Each Nevada public utility must obtain 5% of their annual energy requirements from a renewable energy system in 2004 increasing to 7% in 2005 and 2% more every two years until 2013 when 15% of such annual energy requirements must be provided by renewable energy systems. Our projects located in Nevada assist Sierra Pacific Power Company in meeting this obligation. The proposed Galena project and the potential to sell Renewable Energy Credits from existing station usage at several of the projects to Sierra Pacific Power Company is expected to provide continuous attractive revenue opportunities for each of the projects. There are provisions in purchased power agreements for newly constructed projects that may require the owner and producer to reimburse the public utility if projected amounts of electricity are not delivered each year. The amount of any such penalty may be determined by the NPUC. The NPUC has not determined the amount of or whether any such penalty is likely to be imposed. We expect the output of new projects to meet projected minimum levels and therefore do not anticipate any penalties. Thus we do not anticipate any material decrease in revenue from new projects and there exists opportunity for additional revenues from both new and existing projects from the sale of Renewable Energy Credits.

Permit Status

While our power generation operations produce electricity without emissions of certain pollutants such as nitrogen oxide, and with far lower emissions of other pollutants such as carbon dioxide, some of our projects do emit air pollutants in quantities that are subject to regulation under applicable environmental air pollution laws. Such operations typically require air permits. Especially critical to our geothermal operations are those permits and standards applicable to the construction and operation of geothermal wells and brine reinjection wells. In the United States, injection wells are regulated under the federal Safe Drinking Water Act Underground Injection Control, which we refer to as UIC, program. Our injection wells typically fall into UIC Class V, one of the least regulated categories, because fluids are reinjected to enhance utilization of the geothermal resource. Our projects are required to comply with numerous federal, regional, state and local statutory and regulatory environmental standards and to maintain numerous environmental permits and governmental approvals required for their operation. Some of the environmental permits and

governmental approvals that have been issued to the projects contain conditions and restrictions, including restrictions or limits on emissions and discharges of pollutants and contaminants, or may have limited terms.

Our operations are designed and conducted to comply with applicable permit requirements. We are not aware of any non-compliance with such requirements that would be likely to result in material fines or penalties.

As of the date of this annual report, all of the material permits and approvals required to construct and operate the projects have been obtained and are currently valid, except for the fact that certain permits for some of the projects are held in the name of predecessor owners, and for those permits which must be transferred or reissued to the correct entity, we believe this will occur in the ordinary course and we have already filed some of these applications. Typically, permit transfers or the reissuance of permits in connection with a change of ownership are routine administrative matters.

Environmental Laws and Regulations

Geothermal operations can produce significant quantities of brine and scale, which builds up on metal surfaces in our equipment with which the brine comes into contact. These waste materials, most of which are currently reinjected into the subsurface, can contain various concentrations of hazardous substances, including arsenic, lead, and naturally occurring radioactive materials. We also use various substances, including isobutene, isopentane, and industrial lubricants, that could become potential contaminants and are generally flammable. As a result, our projects are subject to numerous federal, state and local statutory and regulatory standards relating to the use, storage, fugitive emissions and disposal of hazardous substances. The cost of any remediation activities in connection with a spill or other release of such contaminant could be significant.

Although we are not aware of any material mismanagement of these materials, including any mismanagement prior to the acquisition of some of our projects, that has impaired any of the project sites, any disposal or release of these materials onto project sites, other than by means of permitted injection wells, could 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 project site (which we lease), but because of significant surface disturbance and construction since that time further physical evaluation 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 gas service station, it is likely that the former facilities and any associated underground storage tanks would have already been encountered if they still existed.

ITEM 2. PROPERTIES

Ormat Funding Corp. does not lease or own any properties. Our corporate offices are leased by our parent and we make payments to our parent in respect of their lease. Our offices are located at 980 Greg Street, Sparks Nevada 89431. We believe that our current corporate office facilities are adequate for our operations as currently conducted.

Each of our projects is located on property leased or owned by one of our subsidiaries, or is property that is subject to a concession agreement.

ITEM 3. LEGAL PROCEEDINGS

In September 2003, Brady received a threat of litigation from Worldcall Corporation, the successor in interest to the reorganized debtor in the Munson Geothermal, Inc. bankruptcy (pursuant to which we bought the Brady project). Worldcall asserts a claim in the principal amount of $949,155 for royalty payments allegedly arising from the plan of reorganization confirmed in the bankruptcy proceedings. On May 12, 2004, a formal complaint was filed by Wordcall with the Second Judicial District Court of the State of Nevada in the County of Washoe. Court hearings are scheduled for August 2006. We believe that Worldcall's claim is without merit and intend to vigorously defend against it. We have an indemnity from the prior owner of the plant for this claim which relates to periods before we were the owner of the plant.

In August 2003, Ormesa agreed to enter into binding arbitration with the Imperial Irrigation District in connection with the Imperial Irrigation District's claim that Ormesa is obligated to pay scheduling and transmission charges (including those applicable to the GEM 2 and GEM 3 plants) through the effective date of relinquishment of nominated capacity for the GEM 2 and GEM 3 plants. The amount in dispute was $529,000. Ormesa contends that it is not obligated to pay the subject charges for the GEM 2 and GEM 3 plants after the January 1, 2003 effective date of the Energy Services Agreement that Ormesa entered into with the Imperial Irrigation District. On December 17, 2004 Ormesa and the Imperial Irrigation District entered into a Settlement Agreement and Mutual Release pursuant to which Ormesa paid $330,630 to the Imperial Irrigation District. The terms of such agreement will not have a material impact on our operations or relationship with the Imperial Irrigation District.

As a result of our acquisition of the Steamboat 1 plant and Steamboat 1A plant, our subsidiary Steamboat Geothermal became a party to litigation pending in the Second Judicial District Court in Washoe County, Nevada with Geothermal Development Associates and Delphi Securities, Inc. In April 2002, these plaintiffs initiated a lawsuit against the former owner and operator of the Steamboat 1/1A project. The plaintiffs dispute amounts owing to them pursuant to an agreement, dated July 14, 1985, through which Geothermal Development Associates assigned all of its right, title, and interest in the subject geothermal leasehold property in exchange for a net operating royalty interest in the revenues of the Steamboat 1 plant. Plaintiffs allege damages based upon three separate theories: (1) that the actions of the former owner in developing the Steamboat 1A plant have decreased the output of the Steamboat 1 plant; (2) that general, administrative, and corporate expenses included by the former owner in the calculation of the net royalty amount were overstated for the years 2000 and 2001; and (3) that, in addition to its royalty interest in the Steamboat 1 plant, plaintiffs are entitled to a net revenue royalty interest from the Steamboat 1A plant. This case was originally set for trial in September 2003, but the trial date was continued in order to allow for the plaintiffs to obtain substitute counsel. The plaintiff has now selected new counsel. Prior to the continuance of the trial date, initial evidentiary disclosures had been made, as well as some initial discovery requests. No dispositive motions are pending before the court and the trial date has not been rescheduled. We have initiated settlement discussions with the plaintiffs. As part of such discussions, we received a letter from the plaintiffs in which they assert that, in addition to the amounts they claim are owed to them, they are also entitled to a reasonable net operating royalty from our Galena project. We believe such assertion is without merit and that any outcome of such litigation or settlement discussions will not have a material impact on our results of operations. We estimate that the aggregate amount of all claims subject to such litigation will not exceed $1 million.

In 1997, the Nevada environmental authorities investigated a potential violation of the Federal Endangered Species Act involving the alleged loss of habitat for an endangered species of buckwheat at the Steamboat 2 and 3 facilities. This investigation has since been concluded, and the habitat location that was the subject of the investigation was reclaimed in cooperation with the Nevada Division of Forestry and the United States Fish & Wildlife Service, which we refer to as "USFWS." No penalties have been proposed by the USFWS or the State of Nevada, and based on a meeting with the USFWS and the State of Nevada in January, 2004; we believe this matter has been fully resolved.

In the aftermath of the Enron Corp. bankruptcy and alleged violations of regulations by Enron Corp., FERC staff initiated a review of all of its Qualifying Facility files to confirm compliance with Qualifying Facility regulations. As a part of this investigation, on July 30, 2003, FERC staff issued a letter to Ormesa regarding the Qualifying Facility status of the Ormesa project. In responses dated September 25, 2003 and November 21, 2003, Ormesa provided FERC staff with sworn affidavits confirming the Ormesa project's compliance with Qualifying Facility regulations. FERC staff has taken no further action.

In response to an order issued by a California State Court of Appeals, the California Public Utilities Commission, or "CPUC," has commenced a proceeding before an Administrative Law Judge to address SRAC pricing for Qualifying Facilities for the period December 2000 to March 2001. The California Court of Appeals directed that the CPUC modify short run avoided cost pricing on a retroactive basis to the extent the CPUC determined that SRAC prices were not sufficiently

"accurate" or "correct". On February 15, 2005 the CPUC issued a draft decision affirming that short run avoided cost prices during the disputed period were correct and compliant with PURPA requirements and that no retroactive adjustments are warranted. All parties will have an opportunity to comment on the draft and a final decision from the CPUC could be issued in late March or early April, 2005. If the short run avoided cost prices charged during the period in question were determined by the CPUC not to be "accurate" or "correct", retroactive price adjustments could be required for any of our Qualifying Facilities in California whose payments are tied to SRAC pricing, including the Mammoth and Ormesa projects. Currently it is not possible to predict final resolution of such proceeding, however, any retroactive price adjustment required to be made in relation to any of our projects may require such projects to make refund payments, which could materially affect our financial condition, future results and cash flow.

On April 16, 2004, the FERC issued an order stating that the Ormesa project was not required to reduce its net capacity available for sale to account for power used for reinjection of geothermal fluid, provided that only energy from other Qualifying Facilities was used for such reinjection pumping. On September 22, 2004, the FERC affirmed this ruling, and on October 22, 2004, Southern California Edison Company, which purchases power generated by the Ormesa project, appealed such determination to the U.S. Court of Appeals for the District of Columbia Circuit.

From time to time, we (and our subsidiaries) are a party to various other lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of our (and their) business. These actions typically seek, among other things, compensation for alleged personal injury, breach of contract, property damage, punitive damages, civil penalties or other losses, or injunctive or declaratory relief. With respect to such lawsuits, claims and proceedings, we accrue reserves in accordance with U.S. generally accepted accounting principles. We do not believe that any of these proceedings, individually or in the aggregate, would materially and adversely affect our business, financial condition, future results and cash flow.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

PART II


ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

There is no trading market for the equity interests in Ormat Funding Corp. Ormat Nevada owns 100% of the capital stock of Ormat Funding Corp. We have not declared any dividends and are generally restricted from paying dividends under the indenture governing our Senior Secured Notes.

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth our selected consolidated financial data for the years ended and at the dates indicated. We have derived the selected consolidated financial data for the years ended December 31, 2004, 2003 and 2002 and as of December 31, 2004 and 2003 from our audited consolidated financial statements set forth in Part II Item 8 to this annual report. We have derived the selected consolidated financial data for the period from June 29, 2001 to December 31, 2001 and as of December 31, 2002 and 2001 from our audited consolidated financial statements not included herein.

We have omitted from the Selected Financial Data the consolidated financial data of Brady Power Partners, our predecessor entity, for the year ended December 31, 2000, and the period beginning January 1, 2001 to June 28, 2001. This consolidated financial data has been omitted because when Brady Power Partners was acquired by ORNI 1 and ORNI 2 on June 29, 2001, separate audited financial statements were not produced nor are they currently available for periods prior to June 29, 2001. The acquisition of the Brady project consisted only of the geothermal power plant and none of the balance sheet information was transferred in connection therewith. Neither we nor any of our parent or subsidiaries received (as a result of the acquisition) any of the information necessary to recreate the financial statements for the period in question. We believe that the omission of these financial statements will not have a material impact on your understanding of our financial results and condition and related trends.

The information set forth below should be read in conjunction with Item 7 — "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements set forth in Part II, Item 8 to this annual report.


	Year Ended December 31,									Period From June 29, 2001 to December 31, 2001
	2004			2003			2002			Period From June 29, 2001 to December 31, 2001
	(in thousands)
Statement of Operations Data:
Revenues:
Energy and capacity	$	48,071		$	41,885		$	31,451		$	3,964
Lease portion of energy and capacity		9,556			—			—			—
Total revenues		57,627			41,885			31,451			3,964
Costs of revenues:
Energy and capacity		33,532			30,387			22,126			2,466
Lease portion of energy and capacity		4,409			—			—			—
Total costs of revenues		37,941			30,387			22,126			2,466
Gross margin		19,686			11,498			9,325			1,498
General and administrative expenses		1,706			1,268			775			169
Operating income		17,980			10,230			8,550			1,329
Interest expense		(18,310	)		(1,994	)		—			—
Interest income and other non-operating income		617			135			73			2
Income before income taxes and equity in income of investee		287			8,371			8,623			1,331
Income tax provision		(74	)		(2,132	)		(2,734	)		(453	)
Equity in income of investee		1,460			141			—			—
Income before cumulative effect of change in accounting principle		1,673			6,380			5,889			878
Cumulative effect of change in accounting principle (net of tax benefit of $125,000)		—			(205	)		—			—
Net income	$	1,673		$	6,175		$	5,889		$	878
Balance Sheet Data (at end of period):
Working capital (deficit)	$	(9,993	)	$	(7,064	)	$	1,713		$	(2,130	)
Property, plant and equipment, net (including construction-in-process)	$	149,291		$	77,215		$	60,468		$	20,214
Total assets	$	235,183		$	133,719		$	77,609		$	23,030
Long-term debt (including current portion):
Ormesa loan	$	—		$	15,474		$	20,000			—
8¼% Senior Secured Notes	$	189,489			—			—			—
Ormat Nevada subordinated loan	$	8,216		$	86,024		$	45,714		$	18,366
Stockholder's equity	$	14,615		$	12,942		$	6,767		$	878
Other Data:
EBITDA, before equity in income of investee (1)	$	28,895		$	15,724		$	11,672		$	1,856
EBITDA margin (2)		50.1	%		37.5	%		37.1	%		46.8	%
EBITDA, as adjusted (1)	$	33,459		$	15,975		$	11,672		$	1,856
Capital expenditures	$	9,601		$	16,994		$	4,746		$	322

(1)

EBITDA, before equity in income of investee represents net income before interest, taxes, depreciation, amortization and accretion and before equity in income of investee. EBITDA, as adjusted, represents EBITDA with the addition of our 50% share in Mammoth-Pacific L.P.'s EBITDA. EBITDA and EBITDA, as adjusted, are presented because we believe it is frequently used by securities analysts, investors and other interested parties in the evaluation of a company's ability to service and/or incur debt. However, other companies in our industry may calculate EBITDA and EBITDA, as adjusted, differently than we do. EBITDA and EBITDA, as adjusted, are not measurement of financial performance under accounting principles generally accepted in the United States of America and should not be considered as an alternative to cash flow from operating activities or as a measure of liquidity or an alternative to net earnings as indicators of our operating performance or any other measures of performance derived in accordance with accounting principles generally accepted in the United States of America. The following table reconciles net income to EBITDA and EBITDA, as adjusted, for the periods indicated:


	Year Ended December 31,								Period From June 29, 2001 to December 31, 2001
	2004			2003			2002		Period From June 29, 2001 to December 31, 2001
	(in thousands)
Net income	$	1,673		$	6,175		$	5,889	$	878
Adjusted for:
Equity in income of investee		(1,460	)		(141	)		–		–
Interest expense (including amortization of deferred financing costs)		18,310			1,994			–		–
Income tax provision		74			2,132			2,734		453
Depreciation, amortization and accretion		10,298			5,564			3,049		525
EBITDA		28,895			15,724			11,672		1,856
Equity in income of investee		1,460			141
Depreciation, amortization and taxes attributable to our equity in
Mammoth-Pacific L.P		3,104			110
EBITDA as adjusted	$	33,459		$	15,975		$	11,672	$	1,856


(2)	EBITDA margin represents EBITDA as a percentage of total revenues.


ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion and analysis of our results of operations, financial condition and liquidity in conjunction with our consolidated financial statements and the related notes. Some of the information contained in this discussion and analysis or set forth elsewhere in this annual report, including information with respect to our plans and strategies for our business, statements regarding the industry outlook, our expectations regarding the future performance of our business, and the other non-historical statements contained herein are forward-looking statements. See "Cautionary Note Regarding Forward-Looking Statements". You should also review the "Risk Factors" section under this Item for a discussion of important factors that could cause actual results to differ materially from the results described herein or implied by such forward-looking statements.

General

Overview

We are engaged in the geothermal energy power business. We were formed in December 2001, to develop, construct and own, through certain direct and indirect subsidiaries, clean, environmentally friendly geothermal power projects in the United States. Our business currently consists of our investment in power plants producing electricity from geothermal resources. Our business is characterized by relatively predictable revenues generated by our power plants pursuant to long-term power purchase agreements, with terms which are generally up to 20 years. We have increased our net ownership interest in generating capacity by 59 MW between December 31, 2002 and December 31,

2004, of which 47 MW was attributable to our acquisition of geothermal power plants from third parties and 12 MW was attributable to increased generating capacity of our existing geothermal power plants resulting from plant technology upgrades and improvements to our geothermal reservoir operations, which include improving methods of heat source supply and delivery.

In 2004, total revenues generated by our wholly-owned power plants were $57.6 million. In addition, our 50% share in the Mammoth project's revenues in 2004 was $7.9 million. Our net ownership in our generating capacity has increased from 16 MW as of December 31, 2001, to 114 MW as of December 31, 2004.

When making decisions about potential acquisitions or the development of new projects, our management typically focuses on the internal rate of return of the relevant investment, relevant technical and geological matters and other relevant business considerations. Additionally, our management evaluates our operating projects based on the performance of such projects in terms of revenues and expenses in contrast to projects that are under development, which our management evaluates based on costs attributable to each such project.

Our results of operations have varied significantly and are expected to continue to vary due to our history of acquisitions as summarized below:


•	Brady Project. On June 29, 2001, Ormat Nevada, through two of its subsidiaries, acquired 100% of the Brady plant from affiliates of Florida Power and Light Company and Tomen Corporation (a Japanese general trading company) and 100% of the Desert Peak 1 plant from an affiliate of CalEnergy Company, Inc. On July 10, 2002, Ormat Nevada contributed these subsidiaries to us.

•

Ormesa Project. On April 15, 2002, we acquired various entities that together accounted for 100% of the Ormesa project from affiliates of Caithness Energy, LLC, Constellation Energy Group, Florida Power and Light, the Superior Group (a financial services company) and Verizon Capital (f/k/a Bell Atlantic). Such acquisition was accounted for pursuant to the purchase method of accounting in accordance with SFAS No. 141.


•	Steamboat 1/1A Project. On June 30, 2003, ORNI 7 acquired 100% of the Steamboat 1/1A project from Far West Capital, Inc. (an investment firm) and U.S. Energy Systems, Inc.


•	Mammoth Project. On December 18, 2003, Ormat Nevada indirectly acquired a 50% interest in the Mammoth project from Covanta Energy Corporation. On January 30, 2004, Ormat Nevada contributed its interest in the Mammoth project to us.

•

Steamboat 2/3 Project. On February 13, 2004, we acquired, through one of our subsidiaries, ORNI 7, 100% of the Steamboat 2/3 project from Far West Capital, Inc. (an investment firm) for a total cost of approximately $74.4 million. The acquisition of the Steamboat 2/3 project was financed with a portion of the proceeds received from the issuance of the Senior Secured Notes. Such acquisition was accounted for pursuant to the purchase method of accounting in accordance with Statement of Financial Accounting Standards ("SFAS") No. 141.


•	As transfers of the Brady project, the Steamboat 1/1A project and the Mammoth project were made between companies under common control, they have been accounted for in a manner similar to a pooling of interests, and have been presented in the financial statements as having occurred as of June 29, 2001, June 30, 2003 and December 18, 2003, respectively.

As a result of these acquisitions, our results for the various periods contained in the financial statements in this annual report may not be comparable with each other or indicative of future results, and they may be of limited value to you in analyzing our company. Additionally, because we acquired most of these interests from unrelated third parties, our ability to comment on the reasons for variations in the historical operating results of the acquired entities prior to the date of acquisition is limited.

Recent Developments

$190 million in aggregate principal amount of the Senior Secured Notes was issued on February 13, 2004 in a capital markets offering subject to Rule 144A and Regulation S of the Securities Act of

1933, as amended. On March 16, 2005, we completed an offering to exchange $1,000 principal amount of our Senior Secured Notes that were registered under the Securities Act of 1933, as amended, for each $1,000 principal amount of our outstanding Senior Secured Notes. Currently, there is $189,488,618 in aggregate principal amount of Senior Secured Notes outstanding.

Trends and Uncertainties

The geothermal industry in the United States has historically experienced significant growth followed by a consolidation of owners and operators of geothermal power plants. During the 1990s, growth and development in the geothermal industry occurred primarily in foreign markets and only minimal growth and development occurred in the United States. Since 2001, there has been increased demand for energy generated from geothermal resources in the United States as production costs for electricity generated from geothermal resources have become more competitive relative to fossil fuel generation due to increasing gas prices and as a result of newly enacted legislative and regulatory incentives, such as state renewable portfolio standards and such as the production tax credit bill that allow owners of geothermal power plants to claim credits on electricity sold during the first five (5) years after a project achieves commercial operation. We see the increasing demand for energy generated from geothermal and other renewable resources in the United States and the further introduction of renewable portfolio standards and the production tax credit as the most significant trends affecting our industry today and in the immediate future. Our operations and the trends that from time to time impact our operations are subject to market cycles.

Although other trends, factors and uncertainties may impact our operations and financial condition, including many that we do not or cannot foresee, we believe that our results of operations and financial condition for the foreseeable future will be affected by the following trends, factors and uncertainties:


•	We expect to continue to generate all of our revenues from the sale of electricity from our power plants. All of our current revenues from the sale of electricity are derived from fully-contracted payments under long-term power purchase agreements.

•

The viability of the geothermal resources utilized by our power plants depends on various factors such as the heat content of the geothermal reservoir, useful life of the reservoir (the term during which such geothermal reservoir has sufficient extractable fluids for our operations) and operational factors relating to the extraction of the geothermal fluids. Our geothermal power plants may experience an unexpected decline in the capacity of their respective geothermal wells. Such factors, together with the possibility that we may fail to find commercially viable geothermal resources in the future, represent significant uncertainties we face in connection with our operations.


•	We have experienced significant growth through the acquisition of the Steamboat 2/3 project and we expect to experience additional growth due to the enhancement of the Mammoth and Ormesa projects and the construction of the Galena project. As a result of the Steamboat 2/3 project acquisition, we increased our revenues and operating profits during the year ended December 31, 2004.

•

We expect to continue to benefit from the increasing demand for renewable energy as a result of favorable legislation adopted by California and Nevada (where all of our projects are located). In both states, relevant legislation currently requires that an increasing percentage of the electricity supplied by electric utility companies operating in such states be derived from renewable energy resources until certain pre-established goals are met. We expect that the additional demand for renewable energy from utilities in such states will create additional opportunities for us to expand existing projects.


•	As a result of the issuance of our Senior Secured Notes, our interest expenses for the fiscal year ended December 31, 2004 increased, as compared to our interest expenses for the fiscal year ended December 31, 2003.

Revenues

All of our revenues are, and will continue to be, derived from payments under our subsidiaries' power purchase agreements. Equity distributions due to us from our 50% interest in the Mammoth project are dependent upon payments under its power purchase agreements. Such revenues are subject to seasonal variations, as more fully described below in the section entitled "Seasonality".

Most of our power purchase agreements provide for the payment of capacity and energy payments. Generally, capacity payments are payments calculated based on the amount of time that our power plants are available to generate electricity. Some of our power purchase agreements provide for bonus capacity payments in the event that we are able to exceed certain target levels and the potential forfeiture of payments if we fail to meet minimum target levels. Energy payments, on the other hand, are payments calculated based on the amount of electrical energy delivered to the relevant power purchaser at a designated delivery point. The rates applicable to such payments are either fixed (subject, in certain cases, to certain adjustments) or are based on the relevant power purchaser's short run avoided costs (the incremental costs that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others).

As required by Emerging Issues Task Force No. 01-8, Determining Whether an Arrangement Contains a Lease, we assessed all of our power purchase agreements acquired since July 1, 2003, and concluded that the agreements related to our Steamboat 2/3 project contained a lease element requiring lease accounting. Accordingly, revenues related to the lease element of the agreements are presented as "lease portion of energy and capacity" revenue, with the remaining revenue related to the production and delivery of the energy presented as "energy and capacity" revenue in our financial statements. As the lease revenue and the energy and capacity revenues are derived from the same arrangement, we analyze such revenues, and related costs, on a combined basis for management purposes.

Seasonality

The demand for the electricity generated by our projects and the prices paid for such electricity pursuant to our power purchase agreements are subject to seasonal variations. The demand for electricity from the Ormesa project and the Mammoth project is the highest in the summer months of June through September, because the power purchaser for those projects, Southern California Edison Company, delivers more electricity to its California markets during such period in order to meet demand for air conditioning and other energy-intensive cooling systems utilized during such summer months. The demand for electricity from the Steamboat complex and the Brady project is more balanced, consisting of both summer and winter peaks that reflect the greater temperature variation in Nevada. In California, the capacity rates payable pursuant to the applicable power purchase agreement are higher in the summer months and as a result we receive higher revenues during such months. In contrast, there are no significant changes in prices during the year payable pursuant to our power purchase agreement for the Nevada projects. In the winter, due principally to the lower ambient temperature, our power plants produce more energy and as a result we receive higher energy revenues. However, the higher capacity payments payable by the power purchaser in California in the summer months as a result of the increase in demand and in prices has a more significant impact on our revenues than that of the higher energy revenues generally generated in winter due to increased efficiency, and as a result our revenues are generally higher in the summer than in the winter.

Expenses

The principal expenses attributable to each of our operating projects include expenses under the operations and maintenance agreements between each project and Ormat Nevada, such as salaries, lease expenses, royalties, geothermal fluid supply, startup and auxiliary electricity purchases, property tax and insurance, and, for the California projects, transmission charges, scheduling charges and sweet water purchases for plant cooling towers.

The principal project expenses under the operations and maintenance agreement include:


•	For each project other than the Mammoth project, a fixed monthly fee, subject to adjustments based on the Consumer Price Index, Urban Consumers-West based on January 1 of each year, which covers all costs associated with staffing, administration, ordinary maintenance and certain incidental costs at each plant and routine replacement of parts and consumables (other than for the wells).

•

For each project other than the Mammoth project, actual cost and expenses plus a 10% mark-up for certain "extraordinary operation expenses." These extraordinary operation expenses include all major corrective maintenance work, any modifications, additions, or deletions to the projects' equipment, any cost incurred as a result of any change in law, authorizations, power purchase agreements, plant connection agreement or in exercise of emergency management powers, any cost incurred by Ormat Nevada with respect to our environmental responsibilities, and work in connection with the geothermal fields and wells described in the operations and maintenance agreement.


•	Payments to government agencies and private parties for the use of geothermal resources and site leases where plants are situated are recorded as a component of cost of revenues. For the year ended December 31, 2004, such expenses were less than 1% of revenues.


•	Royalty payments are payments made as compensation for the right to use certain geothermal resources and are included as a component of cost of revenues and are paid as a percentage of the revenues derived from the associated geothermal rights. For the year ended December 31, 2004, royalties were approximately 2.2% of revenues.

Under a fluid supply agreement, Brady pays to Western States a royalty payment of 1% of the net revenues of the Desert Peak 1 plant derived from the sale of electricity under the Brady project's power purchase agreement and reimburses Western States for certain costs. These payments are included as a component of cost of revenues.

Critical Accounting Policies

Our significant accounting policies are more fully described in Note 1 to our audited consolidated financial statements set forth in Part II Item 8 of this annual report. However, certain of our accounting policies are particularly important to the portrayal of our financial position and results of operations. In applying these critical accounting policies, our management uses its judgment to determine the appropriate assumptions to be used in making certain estimates. Such estimates are based on management's historical experience, the terms of existing contracts, management's observance of trends in the geothermal industry, information provided by our customers and information available to management from other outside sources, as appropriate. Such estimates are subject to an inherent degree of uncertainty. Our critical accounting policies include:


•	Revenues. Revenues related to the sale of electricity from our geothermal power plants and capacity payments paid in connection with such sale are recorded based upon output delivered and capacity provided by such power plants at rates specified pursuant to the relevant power purchase agreements.

•

Determining Whether an Arrangement Contains a Lease. In May 2003, the Emerging Issues Task Force ("EITF") reached consensus in EITF Issue No. 01-8, Determining Whether an Arrangement Contains a Lease, to clarify the requirements of identifying whether an arrangement contains a lease at its inception. The guidance in the consensus is designed to broaden the scope of arrangements, such as power purchase agreements, accounted for as leases. EITF No. 01-8 requires both parties to an arrangement to determine whether a service contract or similar arrangement is, or includes, a lease within the scope of SFAS No. 13, Accounting for Leases. The consensus is being applied prospectively to arrangements agreed to, modified, or acquired in business combinations on or after July 1, 2003. The adoption of EITF No. 01-8 effective July 1, 2003 did not have a material effect on our financial position or results of operations. The power purchase agreement acquired in connection with the

acquisition of the Steamboat 2/3 project contains a lease element within the scope of SFAS No. 13. Accordingly, for the year ended December 31, 2004, revenues and costs associated with the lease element of the Steamboat 2/3 power purchase agreements have been presented as "lease portion of energy and capacity" revenue, with the remaining revenue related to the production and delivery of the energy being presented as "energy and capacity" revenue in our financial statements.

•

Impairment of Long-lived Assets and Long-lived Assets to Be Disposed of. Long-lived assets including unconsolidated investments and power purchase agreements are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated future net undiscounted cash flows expected to be generated by the relevant asset. The significant assumptions that we use in estimating our undiscounted future cash flows include: (i) projected generating capacity of the project and rates to be received under the respective power purchase agreements, and (ii) projected operating expenses of the relevant project. If assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value, less costs to sell. Our assessment regarding the existence of impairment factors is based on market conditions, operational performance and legal factors relating to our business. Our review of existing factors and the resulting appropriate carrying value of our long-lived assets are subject to judgment and estimates that management is required to make. We believe that no impairment exists for our long-lived assets, however future estimates as to the recoverability of such assets may change based on revised circumstances.

•

Obligations Associated with the Retirement of Long-Lived Assets. Effective January 1, 2003, we adopted SFAS No. 143, Accounting for Obligations Associated with the Retirement of Long-Lived Assets. Pursuant to SFAS No. 143, entities are required to record the fair market value of any legal liability related to the retirement of any of its assets in the period in which such liability is incurred. Our liabilities related to the retirement of our assets include our obligation to capping wells upon termination of our operating activities, the dismantling of our geothermal power plants upon cessation of our operations and the performance of certain remedial measures related to the land on which such operations were conducted. When a new liability for an asset retirement obligation is recorded, we capitalize the costs of such liability by increasing the carrying amount of the related long-lived asset. Such liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. At retirement, an entity either settles the obligation for its recorded amount or incurs a gain or a loss with respect thereto, as applicable. We estimate the costs related to such liabilities and if such estimates are incorrect, and then the capitalized costs and carrying amount of the related long-lived asset will change and as a result may affect our financial condition and results of operation.

•

Derivative Instruments. SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted by other related accounting literature, establishes accounting and reporting standards for derivative instruments (including certain derivative instruments embedded in other contracts). SFAS No. 133 requires companies to record derivatives on their balance sheets as either assets or liabilities measured at their fair value unless such instruments are exempted from derivative treatment as a normal purchase and normal sale. All changes in the fair value of derivatives are recognized currently in earnings unless specific hedge criteria are met, which requires a company to formally document, designate and assess the effectiveness of transactions that receive hedge accounting.

We adopted and have become subject to the provisions of SFAS No. 133 Derivative Implementation Group ("DIG") Issue No. C15 (DIG Issue No.C15), Normal Purchases and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity, which expands the requirements for the normal purchase and normal sales

exception to include electricity contracts entered into by a utility company when certain criteria are met. Also, pursuant to DIG Issue No. C15, contracts that have a price adjustment clause based on an index that is not directly related to the electricity generated, as defined in SFAS No. 133, do not meet the requirements for the normal purchases and normal sales exception. We have power sales agreements that qualify as derivative instruments under DIG Issue No. C15 and do not meet the exception as they have a price adjustment clause based on an index that does not directly relate to the sources of the power used to generate the electricity. Our adoption of the provisions of DIG Issue No.C15 in 2002 did not have a material impact on our consolidated financial position and results of operations.

In June 2003, the FASB issued DIG Issue No. C20, Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature. DIG Issue No. C20 specified additional circumstances in which a price adjustment feature in a derivative contract would not be an impediment to qualifying for the normal purchases and normal sales scope exception under SFAS No. 133. DIG Issue No. C20 was effective as of the first day of the fiscal quarter beginning after July 10, 2003, or October 1, 2003 for us. DIG Issue No. C20 requires contracts that did not previously qualify for the normal purchases and normal sales scope exception, and do qualify for the exception under DIG Issue No. C20, to freeze the fair value of the contract as of the date of the initial application, and amortize such fair value over the remaining contract period. Upon our adoption of DIG Issue No. C20, we elected the normal purchase and normal sales scope exception under FAS No. 133 related to our power purchase agreements. Such adoption did not have a material impact on our consolidated financial position and results of operations.

•

Accounting for Income Taxes. As part of the process of preparing our consolidated financial statements, we are required to estimate our income tax in the jurisdictions in which we operate. This process requires us to estimate our actual current tax exposure and make an assessment of temporary differences resulting from differing treatment of items for tax and accounting purposes. Such differences result in deferred tax assets and liabilities which are included in our consolidated balance sheet. We must then assess the likelihood that our net deferred tax assets will be recovered from future taxable income and, to the extent we believe that such recovery is not likely, we must establish a valuation allowance. To the extent we establish a valuation allowance or increase such allowance in a period, we must include an expense within the tax provision in our consolidated statement of operations. Management uses significant judgment in determining our deferred tax assets and liabilities and any valuation allowance recorded against our net deferred tax assets. In the event that we generate taxable income and we have net operating loss carryforwards for which a deferred tax valuation allowance has been established, we may be required to adjust our valuation allowance. We account for investment tax credits and we will account in the future, if applicable, for production tax credits as a reduction to income tax in the year in which the credits arise.

New Accounting Pronouncements

Consolidation of Variable Interest Entities.

In January 2003, the Financial Accounting Statements Board, which we refer to as FASB, issued Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB 51, which we refer to as FIN No. 46, as amended by FIN No. 46R in December 2003. Among other things, FIN No. 46R generally deferred the effective date of FIN No. 46 to the quarter ended March 31, 2004. The objectives of FIN No. 46R are to provide guidance on the identification of Variable Interest Entities, which we refer to as VIEs, for which control is achieved through means other than ownership of a majority of the voting interest of an entity, and how to determine which company (if any), as the primary beneficiary, should consolidate such VIE. A variable interest in a VIE, by definition, is an asset, liability, equity, contractual arrangement or other economic interest that absorbs the entity's economic variability. Effective as of March 31, 2004, we adopted FIN No. 46R, which did not have a material impact on our consolidated results of operations and financial position.

Exchange of Non-monetary Assets

In December 2004, the FASB issued SFAS No. 153, Exchanges of Non-monetary Assets — An Amendment of APB Opinion No. 29. SFAS No. 153 amends APB Opinion No. 29, Accounting for Non-monetary Transactions. The amendments made by SFAS No. 153 are based on the principle that exchanges of non-monetary assets should be measured based on the fair value of the assets exchanged. Further, the amendments eliminate the exception for nonmonetary exchanges of similar productive assets and replace it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. The provisions in SFAS No. 153 are effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005 (July 1, 2005 for us). Early application of SFAS No. 153 is permitted. The provisions of SFAS No. 153 shall be applied prospectively. We do not expect SFAS No. 153 to have a material impact on our results of operations and financial position in future periods.

Whether an Investor Should Apply the Equity Method of Accounting to Investments Other Than Common Stock

In July 2004, the FASB issued EITF Issue No. 02-14, Whether an Investor Should Apply the Equity Method of Accounting to Investments Other Than Common Stock. EITF Issue No. 02-14 addresses whether the equity method of accounting applies when an investor does not have an investment in voting common stock of an investee but exercises significant influence through other means. EITF Issue No. 02-14 states that an investor should only apply the equity method of accounting when it has investments in either common stock or in-substance common stock of the investee, provided that the investor has the ability to exercise significant influence over the operating and financial policies of the investee. The provisions in EITF Issue No. 02-14 are effective for reporting periods beginning after September 15, 2004 (October 1, 2004 for us). The adoption of EITF Issue No. 02-14 by us did not have any our impact on our results of operations and financial position.

Results of Operations

Our historical operating results in dollars and as a percentage of total revenues are presented in the tables below. A comparison of the years described below may be of limited value as a result of the effects that our recent acquisitions and enhancements of acquired projects have had on our historical operating results.


	Year Ended December 31,
	2004			2003			2002
	(in thousands)
Statement of operations historical data:
Revenues:
Energy and capacity	$	48,071		$	41,885		$	31,451
Lease portion of energy and capacity		9,556			—			—
Total revenues		57,627			41,885			31,451

Costs of revenues:
Energy and capacity		33,532			30,387			22,126
Lease portion of energy and capacity		4,409			—			—
Total cost of revenue		37,941			30,387			22,126

Gross margin		19,686			11,498			9,325

General and administrative expenses		1,706			1,268			775
Operating income		17,980			10,230			8,550
Other income (expense):
Interest income		567			23			1
Interest expense		(18,310	)		(1,994	)		—
Other non-operating income		50			112			72
Income before income taxes and equity in income of investee		287			8,371			8,623
Income tax provision		(74	)		(2,132	)		(2,734	)
Equity in income of investee		1,460			141			—
Income before cumulative effect of change in accounting principle		1,673			6,380			5,889
Cumulative effect of change in accounting principle, net of tax benefits		—			(205	)		—
Net income	$	1,673		$	6,175		$	5,889


	Year Ended December 31,
	2004			2003			2002
Statement of operations percentage data:
Revenues:
Energy and capacity		83.4	%		100.0	%		100.0	%
Lease portion of energy and capacity		16.6			—			—
Total revenues		100.0			100.0			100.0

Costs of revenues:
Energy and capacity		58.2			72.5			70.4
Lease portion of energy and capacity		7.6			—			—
Total cost of revenue		65.8			72.5			70.4

Gross margin		34.2			27.5			29.6

General and administrative expenses		3.0			3.0			2.4
Operating income		31.2			24.5			27.2
Other income (expense):
Interest income		1.0			—			—
Interest expense		(31.8	)		(4.8	)		—
Other non-operating income		0.1			0.3			0.2
Income before income taxes and equity in income of investee		0.5			20.0			27.4
Income tax provision		(0.1	)		(5.1	)		(8.7	)
Equity in income of investee		2.5			0.3			—
Income before cumulative effect of change in accounting principle		2.9			15.2			18.7
Cumulative effect of change in accounting principle, net of tax benefits		—			(0.5	)		—
Net income		2.9	%		14.7	%		18.7	%

Comparison of the Year Ended December 31, 2004 and the Year Ended December 31, 2003

Total Revenues

Total revenues for the year ended December 31, 2004 were $57.6 million, which represented a 37.6% or $15.7 million increase over total revenues of $41.9 million for the year ended December 31, 2003. This increase in revenues was primarily the result of:


a)	a $14.4 million increase in the revenues of the Steamboat complex, which amounted to $15.4 million for the year ended December 31, 2004, as compared with $1.0 million for the year ended December 31, 2003. This increase in revenues was primarily a result of the acquisitions of the Steamboat 1/1A project on June 30, 2003 and the Steamboat 2/3 project on February 11, 2004; and

a 2% increase in revenues from our Ormesa project which amounted to $31.1 million for the year ended December 31, 2004, as compared to $30.5 million for the year ended December 31, 2003. This increase in revenues was primarily a result of installing two new power units at the Ormesa project in July 2003, which increased power generation by 8 MW, offset by a reduction in revenues primarily due to lower well availability and two major failures. One of the failures was an insurable event, and insurance proceeds were received, and the other failure was not.

Total Cost of Revenues

Total cost of revenues for the year ended December 31, 2004 were $37.9 million, which represented a 24.9% increase over total cost of revenues of $30.4 million for the year ended December 31, 2003. The increase was principally due to the acquisition of the Steamboat complex, as cost of revenues for the year ended December 31, 2004 included $8.3 million of expenses related to the Steamboat complex, while for the year ended December 31, 2003, $0.9 million from the Steamboat complex were included. The remaining $0.1 million increase in total cost of revenues for the year ended December 31, 2004 was due to depreciation on capital enhancements related to the Ormesa project that were completed in July 2003, offset by a reduction in Brady's expenses. As a percentage of total revenues, the total cost of revenues was 65.8% for the year ended December 31, 2004 comparable to 72.5% for the year ended December 31, 2003. This decrease was due to the Steamboat 2/3 project, as its cost of revenues percentage was slightly lower than the projects in our portfolio prior to such acquisition. Gross margins were 34.2% for the year ended December 31, 2004 compared to 27.5% for the year ended December 31, 2003. Such increase was due to the Steamboat 2/3 project, as its margin percentage was slightly higher than of the projects in our portfolio prior to such acquisition.

General and Administrative Expenses

General and administrative expenses were $1.7 million for the year ended December 31, 2004, as compared to $1.3 million for the year ended December 31, 2003. The increase of $0.4 million is due to the increased general administrative activity due to the acquisition of the Steamboat project that was operating during the year ended December 31, 2004.

Interest Expense

Interest expense for the year ended December 31, 2004 was $18.3 million, as compared to $2.0 million for the year ended December 31, 2003. The increase was primarily due to $14.8 million of interest expense on the Senior Secured Notes and interest expense of $1.1 million related to notes payable to Ormat Nevada. Prior to December 1, 2003, all amounts owed to Ormat Nevada were interest free. Effective December 1, 2003, we began recording interest expense at an interest rate of approximately 5% per annum on all outstanding balances under notes payable to Ormat Nevada. In addition, during the year ended December 31, 2004, we incurred $0.6 million of additional amortization of deferred financing costs as a result of a one time interest expense of our early repayment of the Ormesa loan on December 31, 2004. See "— Liquidity and Capital Resources".

Income Taxes

Income tax provision for the year ended December 31, 2004 was $0.1 million, as compared with $2.1 million for the year ended December 31, 2003. The effective tax rate for the year ended December 31, 2004 and 2003 was 25.8% and 25.5%, respectively. During the year ended December 31, 2004, our effective tax rate was reduced by approximately 10.5% resulted from depletion deductions of approximately $90,000 for tax purposes in excess of the book basis of geothermal field resources. Such difference is considered a permanent difference. During the year ended December 31, 2003 our effective tax rate was reduced by approximately 15.5% resulting from the generation of investment tax credits related to our enhancements during 2003 of the Ormesa project.

Equity in Income of Investee

Equity in income of investee was $1.5 million (net of income taxes of $0.9 million) for the year ended December 31, 2004 as compared with $0.1 million for the year ended December 31, 2003, representing our 50% ownership interest in the income of Mammoth-Pacific L.P., which was acquired by Ormat Nevada on December 18, 2003 and transferred to us on January 30, 2004.

Net Income

Net income was $1.7 million for the year ended December 31, 2004 and $6.2 million for the year ended December 31, 2003. The decrease of $4.5 million in net income was primarily the result of

offsetting factors, including: (i) an increase of $7.8 million in operating income resulting primarily from the acquisition of the Steamboat 2/3 project, (ii) the increase in equity income from Mammoth of $1.3 million, (iii) an increase of $16.3 million in interest expenses primarily related to the Senior Secured Notes, and (iv) a decrease of $2.0 million in income taxes.

Comparison of the Year Ended December 31, 2003 and the Year Ended December 31, 2002

Total Revenues

Total revenues for the year ended December 31, 2003 were $41.9 million, which represented a 33.2% increase over total revenues of $31.5 million for the year ended December 31, 2002. The increase was principally due to the following:


a)	the acquisition of the Ormesa project on April 15, 2002 whose revenues for the year ended December 31, 2003 amounted to $30.5 million, as compared to $21.8 million for the year ended December 31, 2002;

an 8.3% increase in the revenues of Brady, which amounted to $10.4 million for the year ended December 31, 2003, as compared with $9.6 million for the year ended December 31, 2002. This increase was primary a result of the binary unit that we added to the Brady plant in August 2002. This new binary unit increased power generation by approximately 6 MW, which enabled us to generate additional revenues under the Brady power purchase agreement; and


c)	the replacement of equipment at the Ormesa project in July 2003 which optimized its resource usage so that we were able to generate an additional 8 MW from the project thereby generating additional revenues of approximately $1.5 million.

Total Cost of Revenues

Total cost of revenues for the year ended December 31, 2003 were $30.4 million, which represented a 37.3% increase over total cost of revenues of $22.1 million for the year ended December 31, 2002. The increase was principally due to the acquisition of the Ormesa project on April 15, 2002, as cost of revenues for the year ended December 31, 2003 included $23.4 million of expenses related to the Ormesa project compared to $17.0 million for the year ended December 31, 2002. As a percentage of total revenues, the total cost of revenues was 72.5% for the year ended December 31, 2003, as compared to 70.4% for the year ended December 31, 2002. Gross margins were 27.5% for the year ended December 31, 2003, as compared with 29.6% for the year ended December 31, 2002. The gross margin at the Ormesa project was 23.4% or $7.1 million and 22.1% or $4.8 million, respectively, for the year ended December 31, 2003 and the eight and a half months ended December 31, 2002, while the gross margin of the Brady project was 40.9% or $4.3 million and 46.8% or $4.5 million, respectively, for the years ended December 31, 2003 and 2002, due to higher operating expenses and depreciation expenses as a result of new equipment installed at the Brady project. The Ormesa project was, and is, more expensive to operate than the Brady project because of transmission charges paid to the Imperial Irrigation District, the greater operating expenses associated with a wet cooling system (rather than an air cooling system at the Brady project), sweet water purchases, the large number of wells which provide geothermal resources to the Ormesa project and the relatively large number of employees associated with the Ormesa project. The increase was also due to capital improvements in the Ormesa and Brady power plants which resulted in additional $0.4 million in depreciation for the year ended December 31, 2003. Capital expenditures in July 2003 for the Ormesa project included installing two new power units and modifying the geothermal fluid gathering system and electrical system in order to increase the capacity, reliability and availability of the project. Capital expenditures in August 2002 for the Brady project included installing a new power unit and modifying the steam geothermal unit in order to increase the capacity, reliability and availability of the project.

General and Administrative Expenses

General and administrative expenses were $1.3 million for the year ended December 31, 2003, as compared to $0.8 million for the year ended December 31, 2002. The increase of $0.5 million is due to

the increase in general administrative activity to cover the larger number of assets operated during the year ended December 31, 2003, in which Ormesa was operated for a full year while in 2002 it was operated since April.

Interest Expense

Interest expense for the year ended December 31, 2003 was $2 million, as compared to no interest expense for the year ended December 31, 2002. The increase was primarily due to interest expense of $1.8 million on the Ormesa loan, a $20.0 million amortizing loan borrowed from United Capital on December 31, 2002 that Ormesa incurred in order to fund a portion of the purchase price of the Ormesa project, and $0.2 million related to a note payable to Ormat Nevada that we entered into on December 1, 2003.

Income Taxes

Income tax provision for the year ended December 31, 2003 was $2.1 million, as compared with $2.7 million for the year ended December 31, 2002. The effective tax rate for the year ended December 31, 2003 and 2002 was 25.5% and 31.7%, respectively. Our effective tax rate was lower during the year ended December 31, 2003 compared to the year ended December 31, 2002 resulting from the generation of investment tax credits related to our enhancements during 2003 of the Ormesa project.

Equity Income of Investee

Equity in income of investee was $0.1 million for the year ended December 31, 2003, representing our 50% ownership interest in the income of Mammoth-Pacific L.P., which was acquired by Ormat Nevada on December 18, 2003 and transferred to us on January 30, 2004. As we did not own any interest in Mammoth-Pacific L.P. during the year ended December 31, 2002, we did not have any equity in income of investee during such year.

Net Income

Net income for the year ended December 31, 2003 was $6.2 million, which represented a 4.9% increase over net income of $5.9 million for the year ended December 31, 2002. Gross margin during the year ended December 31, 2003 increased by $2.2 million, which contributed to the increase in net income during 2003. Such increase was offset by an increase of $2.0 million in interest expenses primarily related to the Ormesa long-term loan.

Liquidity and Capital Resources

Our principal sources of liquidity are derived from a combination of internally generated cash and parent subordinated loans, supplemented with third party debt.

Our estimated uses of funds are for planned capital expenditures, described below, and for the repayment of the debt services related to the issuance of the Senior Secured Notes.

Prior to December 1, 2003 amounts owed to Ormat Nevada were interest free and payable from available cash. On December 1, 2003, we entered into a loan agreement with Ormat Nevada pursuant to which we may borrow up to $55 million from time to time. The loan is due in 2021 and is payable only from available cash flow, is subordinated to other debt and has been classified as non-current. Interest accrues on the unpaid principal of the loan amount at a rate per annum equal to the higher of 5% or the applicable Federal rate (5.12% and 4.68% at December 31, 2003 and 2004, respectively), and is added to the principal and is also due in 2021 or from available cash flow.

Our third-party debt is composed of project finance debt for the purpose of refinancing projects or for the acquisition of our projects. On February 13, 2004, we issued the Senior Secured Notes in a capital markets offering subject to Rule 144A and Regulation S of the Securities Act of 1933, as amended, for the purpose of refinancing the acquisition cost of the Brady, Ormesa and Steamboat

1/1A projects, and the financing of the acquisition cost of the Steamboat 2/3 project and Mammoth project. On March 16, 2005, we exchanged these unregistered notes for Senior Secured Notes with substantially identical terms that have been registered under the securities Act of 1933, as amended. Currently, there is $189,488,618 of Senior Secured Notes outstanding. The Senior Secured Notes are collateralized by substantially all of our assets and the assets of our subsidiaries and is jointly and severally fully and unconditionally guaranteed by all of our wholly owned subsidiaries. The collateral securing the Senior Secured Notes consists of (with certain exceptions) all of our and our wholly-owned subsidiaries' real and personal property, contractual rights, revenues and bank accounts, intercompany notes and insurance policies.

On December 31, 2004, Ormesa LLC, our subsidiary, repaid in its entirety a senior secured loan in the amount of $13.1 million under its credit facility with United Capital, a division of Hudson United Bank. The loan was secured by a first priority lien on the Ormesa project and this lien was released contemporaneously with the repayment of the loan. In accordance with the terms of our indenture governing the Senior Secured Notes, immediately upon the repayment of the loan, Ormesa executed a guarantee of the Senior Secured Notes and granted a first priority lien on the Ormesa project and all other Ormesa assets in favor of the collateral agent for the benefit of the holders of the Senior Secured Notes. We repaid the loan with amounts set aside in a cash escrow account that was funded from proceeds from the sale of the Senior Secured Notes.

Our management believes that the projects' generated cash will be sufficient to address our liquidity. Additionally, we have an outstanding balance of $8.2 million of subordinated loan from Ormat Nevada, out of a total of $55 million, as described above. Therefore, we may borrow, if required, up to $46.8 million from Ormat Nevada in order to address other investment requirements.

Historical Cash Flow

The following table set forth the components of our cash flows for the relevant years indicated:


	Year Ended December 31,
	2004			2003			2002
	(in thousands)
Net cash provided by operating activities	$	15,670		$	20,028		$	5,805
Net cash used in investing activities		(101,377	)		(15,962	)		(7,362	)
Net cash provided by (used in) financing activities		85,707			(4,066	)		1,556

For the Year Ended December 31, 2004

Net cash provided by operating activities for the year ended December 31, 2004 was $15.7 million, as compared with $20.0 million for the year ended December 31, 2003. Such decrease was primarily due to: (i) decrease in net income as a result of the increase of $16.3 million in interest expenses, offset by the effect of the acquisition of the Steamboat 2/3 project on February 11, 2004, whose gross margin during the year ended December 31, 2004 amounted to $7.1 million (ii) earnings distributions of $2.1 million from our 50% interest in Mammoth, and (iii) a decrease of $2.1 million in accounts payable for the year ended December 31, 2004, as compared to an increase of $5.0 million for the year ended December 31, 2003, as a result of increase in scheduling and transmission charges payable and debt issuance costs payable.

Net cash used in investing activities for the year ended December 31, 2004 was $101.4 million, as compared with $16.0 million for the year ended December 31, 2003. Capital expenditures for our power facilities of $9.6 million primarily includes $6.4 million for the construction of the Galena project and $1.8 million for the purchase of certain geothermal, mineral and surface rights related to Brady project. This amount reflects a decrease of $7.4 million for year ended December 31, 2004 compared to year ended December 31, 2003 mainly as a result of fewer enhancements to our power facilities performed in 2004. Investing activities in 2004 reflect the use of funds for the acquisition of the Steamboat 2/3 project for a total of $74.4 million, a deposit payment of $2.5 million for the use of the Meyberg property and a net increase in restricted cash of $18.0 million generated from the

proceeds from the issuance of the Senior Secured Notes in February 2004, that are earmarked for capital expenditures and the debt service reserve account established pursuant to the terms governing our Senior Secured Notes. This amount is net of $13.1 million which we used to repay the Ormesa loan on December 31, 2004 and $6.4 million drew out for the construction of the Galena project. These amounts were offset by a distribution of $2.6 million from our 50% investment in Mammoth.

Net cash provided by financing activities for the year ended December 31, 2004 was $85.7 million as compared with net cash used in financing activities for the year ended December 31, 2003 of $4.1 million. The principal factors which affected cash flow from financing activities for the year ended December 31, 2004 were the issuance of the Senior Secured Notes amounting to $190 million, less debt issuance costs of $9.2 million, the net repayment of $79.1 million of the long-term subordinated loan from Ormat Nevada and repayment of $16.0 million of our long-term debt (including full repayment of our loan with United Capital in the amount of $13.1).

For the Year Ended December 31, 2003

Net cash provided by operating activities for the year ended December 31, 2003, was $20.0 million, compared to $5.8 million for the year ended December 31, 2002. Such change was principally attributable to an increase in revenues, in an amount equal to $8.7 million, as a result of the acquisition of the Ormesa project, whose revenues for the year ended December 31, 2003 were $30.5 million.

Net cash used in investing activities for the year ended December 31, 2003 was $16.0 million as compared with $7.4 million for the year ended December 31, 2002. Capital expenditures for our power facilities increased by $12.3 million in 2003 compared to 2002 due to capital expenditures for the Ormesa project during the year ended December 31, 2003 as compared with capital expenditures for the Brady project during the year ended December 31, 2002. Capital expenditures for the Ormesa project included installing two new power units and modifying the geothermal fluid gathering system and electrical system in order to increase the capacity, reliability and availability of the project.

Net cash used in financing activities for the year ended December 31, 2003 was $4.1 million as compared with net cash flow of $1.6 million provided during the year ended December 31, 2002. The principal factors which affected cash flow from financing activities were the net borrowings of $1.9 million of the long-term subordinated loan from Ormat Nevada, payments on our loan with United Capital in the amount of $4.5 million, and deferred debt issuance costs of $1.4 million.

Capital Expenditures

Our capital expenditures primarily relate to the enhancement of existing power plants and the construction of new power plants.

Enhancement and Construction

Mammoth Project. Mammoth-Pacific, L.P. is planning a $5 million enhancement program ($2.5 million to be funded by us) of the Mammoth project, consisting primarily of drilling activities, which we believe will result in an increase in the output of the project by 4 MW and is expected to be completed by 2006. A substantial portion of the funds required for such enhancement have been earmarked by us and our partners for such enhancement program. Mammoth is currently evaluating changes to this enhancement program that may result in additional costs of approximately $2.5 million ($1.25 million to be funded by us).

Ormesa Project. In connection with the Ormesa project, we plan to drill two additional wells, add additional Ormat Energy Converter ("OEC") units and replace existing units in order to increase the output of the project by an estimated 10 MW. We estimate that the costs of such enhancements shall be up to $33 million and will be funded by us from internally generated cash or other available corporate resources. We are currently negotiating with a third party for the sale of the additional output pursuant to a long term power purchase agreement. We expect that such enhancement program will be completed in 2006.

Galena Project. We commenced construction of the Galena project during the third quarter of 2004 and expect that the construction will be complete and that the Galena project will achieve commercial operations in the fourth quarter of 2005. Construction costs of $25.8 million are being funded from the proceeds of the offering of the Senior Secured Notes, which are currently deposited in an escrow account, and will be released in accordance with the progress of the construction phase for such enhancement. Additional costs of construction in the amount of $2 million will be funded out of available cash flow. As of December 31, 2004, approximately $6.4 million in costs had been incurred related to the Galena project. Based on the final design of the project, we plan to increase the entire Steamboat complex's output by a total increase of 13 MW.

We do not anticipate any other material capital expenditures in the near term, other than ordinary maintenance requirements.

Exposure to Market Risks

One market risk to which power plants are typically exposed is the volatility of electricity prices. We do not have significant exposure to such market risk principally because our long-term power purchase agreements have fixed or escalating rate provisions that limit our risk of exposure to changes in electricity prices. However, beginning in May 2007, the energy payments under the Ormesa and Mammoth project power purchase agreements will be determined by reference to the purchaser's short-run avoided costs. The energy prices of Steamboat 1/1A are also dependent on Sierra Pacific Power Company's short-run avoided costs. We estimate that energy payments will represent approximately two-thirds of those projects' revenues after 2007 and there may be some volatility in their revenues as a result.

We anticipate that the majority of our long-term financing will be in the form of fixed rate securities, such as the Senior Secured Notes, and therefore we will not be exposed to changes in interest rates.

Effects of Inflation

Our principal expense, debt service, is not subject to inflation because the Senior Secured Notes have a fixed interest rate. Inflation may directly impact expenses under our operations and maintenance agreements because the fees under those agreements are subject to annual adjustments based on the Consumer Price Index, Urban Consumers-West (which we refer to as the "CPI"). During the period from February 2004 to February 2005, such CPI increased by 2.6%. Expenses under those agreements may also increase as the costs of materials increase, although we believe that any such increase would be modest due to our limited exposure to commodity prices. Lease payments are generally fixed. Royalty payments are generally determined as a percentage of revenues and therefore are not significantly impacted by inflation.

The possible negative impact of inflation may be partially offset by price adjustments built into our power purchase agreements. Because energy payments under the Mammoth (after 2007), Ormesa (after 2007) and Steamboat 1/1A power purchase agreements are subject to adjustment based on short-run avoided cost, to the extent that inflation causes an increase in the amount of short-run avoided cost, higher energy payments could have an offsetting impact to any inflation-driven increase in expenses. Similarly, the energy payments under the Brady and Steamboat 2/3 project power purchase agreements increase every year through the end of their terms, but at a rate which is not directly linked to the CPI.

Overall we believe that the impact of inflation on our business will not be significant.

Contractual Obligations and Commercial Commitments

The following table sets forth our long-term cash contractual obligations, excluding interest as of December 31, 2004 (dollars in thousands):


	Payment due by Period
	Total		2005		2006		2007		2008		2009		Thereafter
Senior Secured Notes due 2020	$	189,489	$	6,090	$	9,611	$	8,932	$	7,835	$	9,140	$	147,881
Ormat Nevada subordinated loan ⁽¹⁾		8,216		—		—		—		—		—		8,216
Total cash contractual obligations	$	197,705	$	6,090	$	9,611	$	8,932	$	7,835	$	9,140	$	156,097


(1)	Represents amounts due in 2021 under the Ormat Nevada subordinated loan for major capital expansion costs and are payable from cash available in the Distribution Account when permitted by Senior Secured Notes' indenture and are due in 2021.

The following table sets forth our interest payments payable in connection with our contractual obligations as of December 31, 2004 (dollars in thousands):


	Payment of Interest due by Period
	Total		2005		2006		2007		2008		2009		Thereafter
Senior Secured Notes due 2020 ⁽¹⁾	$	146,174	$	15,811	$	15,144	$	14,354	$	13,629	$	12,947	$	74,289
Ormat Nevada subordinated loan ⁽²⁾		10,615		—		—		—		—		—		10,615
Total cash contractual obligations	$	156,789	$	15,811	$	15,144	$	14,354	$	13,629	$	12,947	$	84,904


(1)	Beginning on January 8, 2005 we became obligated to pay liquidated damages to all holders of our Senior Secured Notes until the exchange offer was consummated on March 16, 2005. Such liquidated damages total an amount of approximately $91,000 in the aggregate.


(2)	Represents amounts of interest accrues on the unpaid principal due under the Ormat Nevada subordinated loan for major capital expansion costs and are payable from cash available in the Distribution Account when permitted by Senior Secured Notes' indenture and are due in 2021.

Off-Balance Sheet Arrangements.

On June 30, 2004, Ormat Nevada entered into a Letter of Credit Agreement with Hudson United Bank pursuant to which Hudson United Bank agreed to issue one or more letters of credit in the aggregate amount of $15 million, and expiring on June 30, 2007, which shall be extended for successive one-year periods unless notice is provided by either Ormat Nevada or the bank not to extend such expiration date. On July 1, 2004, a letter of credit amounting to $8,125,000 was issued under this agreement, which has been used to replace cash on deposit as reserve funds that were held as a pledge against the Senior Secured Notes. Such letter of credit was increased by $2,674,000 on December 31, 2004.

Concentration of Credit Risk

Our credit risk is currently concentrated with our two major customers, Sierra Pacific Power Company and Southern California Edison.

Southern California Edison accounted for 54% of our total revenues for the year ended December 31, 2004 compared to 73% of our total revenues for the year ended December 31, 2003. Southern California Edison is also the sole purchase agreement counterparty and revenue source for the Mammoth project. Based on publicly available information, Southern California Edison's issuer rating is BBB+ (stable outlook) by S&P and Baa1 (stable outlook) by Moody's.

Sierra Pacific Power Company accounted for 46% of our total revenues for the year ended December 31, 2004 and 27% of our total revenues for the year ended December 31, 2003. Based on publicly available information, Sierra Pacific Power Company's issuer rating is B+ (negative outlook) by S&P and B1 (stable outlook) by Moody's.

If Sierra Pacific Power Company or Southern California Edison fail to make payments under their power purchase agreements with us, this would have a material adverse impact on our financial condition and results of operations.

Risk Factors

You should carefully consider the risk factors set forth below as well as the other information contained in this annual report. The risks described below are not the only risks facing us. The risks described below and additional risks and uncertainties not currently known to us or that we currently deem to be immaterial could materially and adversely affect our business, financial condition or results of operations.

Our financial performance depends on the successful operation of our geothermal power plants, which is subject to various operational risks.

Our financial performance depends on the successful operation of our subsidiaries' geothermal power plants. Operation of these projects involves regulatory risks such as changes in laws or regulations, which could result in increased compliance costs, the need for additional capital expenditures or the reduction of certain benefits currently available to our projects. In addition to those risks, operation of the projects involves a variety of other risks, including:


•	regular and unexpected maintenance and replacement expenditures;


•	the failure of the projects to perform at expected levels of output or efficiency;


•	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 project sites; and


•	catastrophic events such as fires, explosions, earthquakes, floods, releases of hazardous materials, severe storms or similar occurrences affecting our projects or any of the power purchasers or other third parties providing services to the projects.

The occurrence of any of these events could significantly increase the expenses incurred by our projects or reduce the overall generating capacity of our projects and could significantly reduce or entirely eliminate the revenues generated by one or more of the projects, which in turn would reduce our net income and could materially and adversely affect our operations and financial condition.

The operation of the projects also depends upon our ability to meet our contractual obligations, including pursuant to leases, operations and maintenance agreements, and supply agreements. For example, the Brady project leases a production well from ConAgra Foods Inc. in exchange for providing geothermal fluids to ConAgra. If we, any of our affiliates or ConAgra were to terminate this lease, Brady would not have access to this geothermal resource and would need to secure an alternate geothermal resource to fulfill obligations under the Brady power purchase agreement.

Our exploration, development, and operation of geothermal energy resources is subject to geological risks and uncertainties, which may result in decreased performance or increased costs for our projects.

Our business involves the exploration, development and operation of geothermal energy resources. These activities are subject to uncertainties, which vary among different geothermal reservoirs and are in some respects similar to those typically associated with oil and gas exploration, development and exploitation, such as dry holes, uncontrolled releases and pressure and temperature

decline, all of which can increase our operating costs and capital expenditures or reduce the efficiency of our power plants. Because geothermal reservoirs are complex geological structures, we can only estimate their geographic area and sustainable output. The viability of geothermal projects depends on different factors directly related to the geothermal resource, such as the heat content (the relevant composition of temperature and pressure) of the geothermal reservoir, the useful life (commercially exploitable life) of the reservoir and operational factors relating to the extraction of geothermal fluids. Our geothermal energy projects may 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. In addition, we may fail to find commercially viable geothermal resources in the expected quantities and temperatures, which would adversely affect our development of geothermal power projects.

In addition, the operation of existing projects and the development of properties near the projects could adversely affect the geothermal resources supplying the projects. We cannot assure you that other parties will not pursue such development. In addition, affiliates of ours own rights to property nearby some of the projects, including the Steamboat 2/3, Mammoth and Brady projects. These affiliates may construct projects on such property and may use geothermal resources that are otherwise available for our projects. Such uses could be adverse to us and your interests as a note holder. For example, Ormat Nevada has begun exploratory drilling for a project called Desert Peak 2, which is near the Desert Peak 1 site. To date we have not observed any adverse impact on the Desert Peak 1 plant due to this activity but we cannot assure you that this will not change or that we, our affiliates or third parties will not undertake drilling activities in the future that may adversely affect the geothermal resources supplying the projects.

Geothermally active areas, such as the areas in which the projects are located, are subject to frequent low-level seismic disturbances. Serious seismic disturbances are possible and could result in damage to our projects or equipment or degrade the quality of our geothermal resources to such an extent that we could not perform under the relevant power purchase agreement for the affected project, which in turn could reduce our net income and adversely affect our financial condition and operations. If we suffer a serious seismic disturbance, 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.

The cost of operations and the operating performance of geothermal power plants may also be adversely affected by a variety of operating factors. Production and injection wells can require frequent maintenance or replacement. New production and injection wells may be required for the maintenance of operating levels, thereby requiring substantial and unanticipated capital expenditures, which in turn would reduce our revenues and adversely and materially impact our operations and financial condition.

All of our net revenues are attributed to payments by two power purchasers under power purchase
agreements. The failure of any such power purchaser to perform its obligations under the relevant power purchase agreement or the loss of a power purchase agreement due to a default would reduce our net income and could materially and adversely affect our financial condition.

In order to generate revenues, we make electric capacity available and deliver energy to, and receive payments for that energy, and in some cases, electric capacity from certain power purchasers. All of our net revenue is attributed to revenues derived from our power purchasers under the power purchase agreements and we anticipate that for the foreseeable future the power purchasers will provide all of our net revenues. Southern California Edison and Sierra Pacific Power Company accounted for 54% and 46% of our revenues, respectively, for the year ended December 31, 2004. We currently expect that Southern California Edison and Sierra Pacific Power Company will account for most of our cash flow available for the foreseeable future.

Neither we nor any of our subsidiaries, nor any of our affiliates makes any representations as to the financial condition or creditworthiness of any purchaser under a power purchase agreement and nothing in this annual report should be construed as such a representation.

There is a risk that any one or more of the power purchasers may not fulfill their respective payment obligations under their power purchase agreements. For example, as a result of the energy crisis in California, Southern California Edison did not pay until March 2002 $21.2 million due for energy delivered under its power purchase agreements relating to the Ormesa project during the period from November 1, 2000 through March 26, 2001. If any of the power purchasers fails to meet its respective payment obligations under its power purchase agreements, we may not be able to make payments on our outstanding debt and our financial condition could be materially and adversely affected.

In connection with the power purchase agreements for the Ormesa project, Southern California Edison Company has expressed its intent not to pay the contract rate for the power supplied by the GEM 2 and GEM 3 plants to the Ormesa project for auxiliary purposes. The majority of the power produced by the GEM 2 and GEM3 plants is used to supply auxiliary power to the other Ormesa plants. We have commenced discussions with Southern California Edison Company to resolve the dispute. In the interim period, Southern California Edison Company has tentatively agreed to pay a lower fixed price for such power. We cannot evaluate the potential long-term financial impact of a failure to reach a resolution with Southern California Edison Company, because, among other things, the current contract rates will fluctuate beginning May 2007. However, we estimate that the financial loss we will incur as a result of the reduced price paid by Southern California Edison Company may be in the range of $1 million for our fiscal year ending December 31, 2005.

Seasonal variations may cause significant fluctuations in our cash flows.

Our results of operations are subject to seasonal variations. This is primarily because two of our projects receive higher capacity payments under the relevant power purchase agreements during the summer months. Some of our other projects may experience reduced generation during warm periods due to the lower heat differential between the geothermal fluid and the ambient surroundings.

Pursuant to the terms of our power purchase agreements, the failure to supply the contracted capacity thereunder may result in the imposition of penalties.

Pursuant to the terms of the Galena power purchase agreement that we have entered into and under which we will sell electricity from the Galena project that is currently in construction, we may be required to make payments to the power purchaser in an amount equal to the purchaser's replacement costs for renewable energy relating to any shortfall amount of renewable energy that we do not provide as required under the power purchase agreement and which the power purchaser is forced to obtain from an alternate source. In addition, we may be required to make payments to the power purchaser in an amount equal to its replacement costs relating to any renewable energy credits we do not provide as required under the power purchase agreement. We may also be required to pay liquidated damages if certain minimum performance requirements are not met under the power purchase agreement, all of which could materially and adversely affect our business, financial condition and ability to make payments on our outstanding debt obligations. With respect to certain of our power purchase agreements, including Steamboat1/1A, Steamboat 2/3 and Brady, we may also be required to pay liquidated damages to our power purchaser if the project does not maintain availability of at least 85% during applicable peak periods. The maximum aggregate amount of such liquidated damages for the Brady and the Steamboat 2/3 power purchase agreements would be approximately $1.5 million for each project.

The short run avoided costs for our power purchasers may decline, which would reduce our project
revenues and materially and adversely affect our business and financial condition.

Under the power purchase agreements for our projects in California, the price that Southern California Edison Company pays for energy is based upon its short run avoided costs, 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 Company and a number of Qualifying Facility power generators in California, including our

subsidiaries, the energy price component payable by Southern California Edison Company has been fixed through April 2007, and thereafter will be based on Southern California Edison Company's short run avoided costs, as determined by the California Public Utilities Commission, which we refer to as CPUC. These short run avoided costs are made available by Southern California Edison Company to the public and may vary substantially on a monthly basis, based primarily on gas prices and other factors. The levels of short run avoided cost prices paid by Southern California Edison Company may decline following the expiration date of the settlement agreements, which in turn would reduce our project revenues derived from Southern California Edison Company under our power purchase agreements with it and could materially and adversely affect our business, financial condition, future results and cash flow.

In response to an order issued by a California State Court of Appeals, the California Public Utility Commission, or CPUC, has commenced an administrative proceeding before an Administrative Law Judge to address short run avoided cost pricing for Qualifying Facilities for the period spanning from December 2000 to March 2001. The California Court of Appeals directed that the CPUC to modify short run avoided cost pricing on a retroactive basis to the extent that the CPUC determined that short run avoided cost prices were not sufficiently "accurate" or "correct." On February 15, 2005 the CPUC issued a draft decision affirming that SRAC prices during the disputed period were correct and compliant with PURPA requirements and that no retroacive adjustments are warranted. All parties will have an opportunity to comment on the draft and a final decision from the CPUC could be issued in late March or early April 2005. If the short run avoided cost prices charged during the period in question were determined by the CPUC not to be "accurate" or "correct," retroactive price adjustments could be required for any of our Qualifying Facilities in California whose payments are tied to short run avoided cost pricing, including the Mammoth and Ormesa projects. Currently, it is not possible to predict the final resolution of such proceeding, however, any retroactive price adjustment required to be made in relation to any of our projects may require such projects to make refund payments or charge less for future sales, which could materially and adversely affect our business, financial condition, future results and cash flow.

In addition, under certain of the power purchase agreements for our projects in Nevada, the price that Sierra Pacific Power Company pays for energy is based upon its short run avoided costs. These short run avoided costs, and in turn the rates payable by Sierra Pacific Power Company, may decline, which in turn would reduce the aggregate amount of project revenues recovered by our Nevada projects pursuant to the relevant power purchase agreements. Su a decrease in project revenues could adversely affect our business, financial condition, future results and cash flow.

Construction activities and the failure to find expected geothermal resources could adversely affect our business.

We will be making significant capital expenditures in connection with the Galena project, during which we will shut down the Steamboat 1/1A project for a brief period of time and construct an enhanced plant in its place. We will perform construction pursuant to a fixed price, date certain (with certain exceptions for change orders and changed circumstances such as force majeure or change in law) turnkey contract with Ormat Nevada. This enhancement is subject to customary risks associated with the construction of power plants, including risks of delay in completion, cost overruns and failure to perform in accordance with contract terms. Any material delay, cost overrun or unsatisfactory performance could have an adverse effect on our results of operations and under certain circumstances could result in the termination of the related Galena power purchase agreement with Sierra Pacific Power Company.

We also plan to commence an enhancement of the Mammoth project, during which we will be drilling for additional geothermal resources at the Mammoth project. Risks associated with this enhancement include failure to find commercially viable geothermal resources in the expected quantities and temperatures and unintended negative impacts on existing resources.

Our business and the power purchasers' power purchasing activities are subject to substantial regulations and may be adversely affected if we or any of the power purchasers are unable to comply with changes in applicable regulations or requirements.

All of our projects 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 projects. The structure of federal and state energy regulation is currently, and may continue to be, subject to challenges, modifications, the imposition of additional regulatory requirements, and restructuring proposals. We and 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.

The federal government encourages production of electricity from geothermal resources through certain tax subsidies. Our parent, OTec, is permitted to claim in its consolidated federal tax returns approximately 10% of the construction cost of each new geothermal power plant as an energy tax credit against our consolidated federal income taxes, or, alternatively, for new power plants completed after October 22, 2004 through December 2005, to claim a production tax credit of 1.8 cents a kilowatt hour on electricity sales for the first five years after the project is put into service. It is also permitted to deduct, as a depreciation expense on its consolidated federal tax returns, most of the cost of the power plant over five years on an accelerated basis, which results in more of the cost being deducted in the first few years than during the remainder of the depreciation period. Any reduction in such tax incentives could materially and adversely affect our business, financial condition, future results and cash flow.

We must periodically apply for or renew a variety of permits with the California Public Utilities Commission, the Public Utilities Commission of Nevada, and other state agencies. While we believe that we will be able to receive and maintain the permits required to operate our business, the failure to do so could have a material adverse effect on our business. Certain permits for some of the projects are held in the name of predecessor owners, and for those permits which must be transferred or reissued to the correct entity, we believe this will occur in the ordinary course and have already filed some of these applications.

If any of our projects loses its Qualifying Facility status under PURPA, or if amendments to PURPA
are enacted that substantially reduce the benefits currently afforded to our Qualifying Facilities, our
operations would be adversely affected.

The operations of our projects are subject to, and benefit from, the Public Utility Regulatory Policies Act of 1978, as amended, which we refer to as PURPA. Qualifying Facility status under PURPA exempts our projects from PUHCA, most of the provisions of the FPA, and certain state laws concerning rates and the financial and organizational regulation of electric utilities. If any of our projects in which we have an interest loses its Qualifying Facility status, or if amendments to PURPA are enacted that substantially reduce the benefits currently afforded Qualifying Facilities, our operations could be adversely affected.

In the event that one of our projects loses its Qualifying Facility status , such project and we would become subject to the full scope of the FPA and applicable state regulations unless an exemption or waiver applies, such as "exempt wholesale generator" ("EWG", as defined under PUHCA) status or "utility geothermal small power production facility" (as defined under PURPA regulations) status, for such project. EWG status would protect the project and us against PUHCA regulation, but would not exempt the project from FPA or state regulation. The application of PUHCA and such other regulations to our projects would require our operations to comply with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility. In the unlikely event that none of the PUHCA exemptions or waivers is available, we could become a public utility holding company under PUHCA, which could be deemed to occur

prospectively or retroactively to the date that any of our projects lost its Qualifying Facility status. In addition, if this happened, our other projects could lose Qualifying Facility status because our interests in such projects could be considered to be electric utility holding company interests for purposes of the 50% limit on ownership of Qualifying Facilities by electric utilities or electric utility holding companies. As a result of such loss of Qualifying Facility status, the Federal Energy Regulatory Commission, which we refer to as FERC, may order partial refunds of past amounts paid by the relevant power purchaser or order a reduction of the rate pursuant to the power purchase agreement prospectively, or both, and thus could cause the loss of some or all of our revenues payable pursuant to the related power purchase agreement, result in significant liability for refunds of past amounts paid, or otherwise impair the value of our projects.

A loss of Qualifying Facility status also could permit the power purchaser, pursuant to the terms of the particular power purchase agreement, to cease taking and paying for electricity from the relevant project or, consistent with FERC precedent, to seek refunds of past amounts paid or to reduce such rates prospectively, or both. This could cause the loss of some or all of our revenues payable pursuant to the related power purchase agreement, result in significant liability for refunds of past amounts paid, or otherwise impair the value of our project. 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 project 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 projects, which would enable the lenders to exercise their remedies and enforce the liens on the relevant project.

The United States Congress is considering proposed legislation that would amend PURPA by limiting the mandatory purchase obligations of power purchasers under new power purchase agreements. The enactment of such legislation could adversely affect our new projects or enhancements of existing projects that do not have a current power purchase agreement.

A decision by the U.S Court of Appeals to overturn a FERC decision related to the use by a project of power generated from another qualifying facility for auxiliary purposes may adversely affect our
operations and financial results.

According to a recent FERC decision regarding our Ormesa project, a geothermal Qualifying Facility that obtains electricity for the operation of its reinjection pumps from an electric utility must reduce its net capacity available for sale by an equivalent amount. However, the FERC decision held that if the electricity for reinjection pumping is provided by Qualifying Facilities that are cogeneration or small power production facilities, no reduction in net capacity is required. Since electricity for reinjection pumping is provided to the Ormesa project by this type of Qualifying Facility, no change in operations at the Ormesa project is required by the FERC decision. However, a petition for review of this aspect of the FERC's decision has been filed with the U.S. Court of Appeals for the District of Columbia Circuit appealing such FERC decision. If the Court of Appeals were to overturn the FERC's recent decision regarding the use of electricity for reinjection pumping provided by the Qualifying Facilities that are cogeneration or small power production facilities, there could be an adverse effect on revenues received from power sales on the Ormesa facility, and thus, an adverse effect on our operations and financial results.

The costs of compliance with environmental laws, which currently are significant, may increase in the
future and as a result, adversely and materially affect our business and financial condition; any
non-compliance with such laws or regulations may result in the imposition of liabilities which could
also materially and adversely affect our business and financial condition.

Our projects are required to comply with numerous federal, state and local statutory and regulatory environmental standards and to maintain numerous environmental permits and governmental approvals required for construction and/or operation. Some of the environmental permits and governmental approvals that have been issued to the projects contain certain 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 projects could be adversely affected or be subject to fines, penalties or additional costs. In addition, 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 projects, as a result of which the operation of the projects may be limited or suspended. 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.

We could be exposed to significant liability for violations of hazardous substances laws because of the use or presence of such substances at our projects.

Our projects are subject to numerous federal, regional, state and local statutory and regulatory standards relating to the use, storage and disposal of hazardous substances. We use isobutane, isopentane, industrial lubricants and other substances at our projects which are or could become classified as hazardous substances. Hazardous substances are also present in the geothermal fluids themselves. If any hazardous substances are found to have been released into the environment at or by the projects, 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 projects into compliance. Furthermore, 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 there may have at one time been a gas station located on the Mammoth project site, but because of significant surface disturbance and construction since that time further physical evaluation of the former gas station site has been impractical. There may be soil or groundwater contamination and related liability exposure of which we are unaware relating to this site or at any site where we currently conduct operations, even if such contamination preceded our operations, which may be significant and may adversely and materially affect our operations and revenues.

The power generation industry is characterized by intense competition, and we encounter competition from electric utilities, other power producers, and power marketers that could materially and adversely affect our business and financial condition.

The power generation industry is characterized by intense competition from electric utilities, other power producers and power marketers. In recent years, there has been increasing competition in the sale of electricity, in part due to excess capacity in a number of U.S. markets and an emphasis on short-term or "spot" markets, and competition has contributed to a reduction in electricity prices. For the most part, we expect that power purchasers interested in long-term arrangements with a capacity price component will engage in "competitive bid" solicitations to satisfy new capacity demands. This competition could adversely affect our ability to obtain power purchase agreements and the price paid for electricity by the relevant power purchasers. There is also increasing competition between electric utilities, particularly in California where the CPUC has launched an initiative designed to give all electricity consumers the ability to choose between competing suppliers of electricity. This competition has put pressure on electric utilities to lower their costs, including the cost of purchased electricity, and increasing competition in the future will put further pressure on power purchasers to reduce the prices at which they purchase electricity from us.

The existence of a prolonged force majeure event or a forced outage affecting a project could adversely affect our business, financial condition and operations.

If a project experiences a force majeure event, our subsidiary owning that project would be excused from its obligations under the relevant power purchase agreement(s). However, the relevant

power purchaser(s) may not be required to make any capacity or energy payments with respect to the affected project or plant(s) so long as the force majeure event continues and, pursuant to certain of our power purchase agreements, will have the right to prematurely terminate the power purchase agreement. Additionally, to the extent that a forced outage has occurred, the relevant power purchaser may not be required to make any capacity and/or energy payments to the affected project, and if as a result the project fails to attain certain performance requirements under certain of our power purchase agreements, the purchaser may have the right to permanently reduce the contract capacity (and, correspondingly, the amount of capacity payments due pursuant to such agreements in the future), seek refunds of certain past capacity payments, and/or prematurely terminate the power purchase agreement. As a consequence, we may not receive any net revenues from the affected project or plant other than the proceeds from any business interruption insurance that applies to the force majeure event or forced outage after the relevant waiting period and may incur significant liabilities in respect of past amounts required to be refunded. In addition, if the transmission systems of the Imperial Irrigation District experiences a force majeure event or a forced outage which prevents it from transmitting the electricity from the Ormesa project to its power purchaser, the power purchaser would not be required to make any capacity payments with respect to the affected projects so long as such force majeure event or forced outage continues. Accordingly, our business, financial condition and operations may be materially and adversely affected and we may not be able to make payments on our outstanding debt.

Some of our leases will terminate if we do not extract geothermal resources in "commercial quantities," thus requiring us to enter into new leases or secure rights to alternate geothermal resources, none of which may be available on terms as favorable to us as any such terminated lease, if at all.

Most of our geothermal resource leases are for a fixed primary term, and then continue for so long as geothermal resources are extracted in "commercial quantities" or pursuant to other terms of extension. In addition, some of our leases at the Steamboat 2/3, Brady, Ormesa and Mammoth projects are undeveloped and have not yet produced geothermal resources in commercial quantities. Leases that cover land which remains undeveloped and does not produce, or does not continue to produce, geothermal resources in commercial quantities and leases that we allow to expire, will terminate. In the event that a lease is terminated and we determine that we will need that lease once the applicable project is operating, we would need to enter into one or more new leases with the owner(s) of the premises that are the subject of the terminated lease(s) in order to develop geothermal resources from or inject geothermal resources into such premises or secure rights to alternate geothermal resources or lands suitable for injection, all of which may not be possible or could result in increased cost to us, which could adversely affect our business, financial condition and our ability to service our outstanding debt.

We rely upon third parties, including affiliates, to conduct important parts of our business. The failure of these third parties to perform their contractual obligations could adversely affect our ability to operate our projects and meet our financial obligations.

If any of the third parties to the contracts and agreements related to the projects fail to perform any of their obligations thereunder, the viability of the projects, and our business and financial condition may be materially and adversely affected. In addition to the power purchasers, these third parties include, among others:


•	the Bureau of Land Management, which we refer to as the "BLM," under the BLM leases, rights of way and the site license agreements or geothermal resource leases upon which the Brady, Mammoth, Ormesa and Desert Peak 1 plants are located;


•	certain private landowners with respect to site licenses;


•	Western States Geothermal Company, which we refer to as "Western States," our affiliate, under the Fluid Supply Agreement for the Desert Peak 1 plant;


•	Ormat Nevada, our parent, under the operations and maintenance agreements for the projects and the engineering, procurement and construction agreement for the Galena project;


•	the Imperial Irrigation District, which transmits power from the Ormesa project to Southern California Edison and provides water for operation of the Ormesa project; and


•	the lessors, sublessors, easement grantors and other third parties under the leases, subleases, easements and other real property rights and interests that are utilized for the projects.

If any of these third parties:


•	claim that there was a defect in proceedings with respect to the approval of their project documents;


•	claim that their project documents were not duly authorized by them;


•	disavow their obligations under their project documents or are excused from performance thereunder pursuant to any bankruptcy, insolvency or other similar proceedings;


•	fail to perform their contractual or other obligations; or


•	are excused from performing their obligations because we have failed to perform our obligations or because of a force majeure event or for any other reason,

the projects may not be able to obtain alternate customers, suppliers, goods or services, as the case may be, to cover such nonperformance, or any replacement agreement for such services that we may enter into may not contain terms and conditions as favorable to us as the initial agreements for such services. Similarly, the possession or use of any real estate needed for the facilities may be curtailed or terminated without the possibility of replacement or relocation. In particular, certain of our real estate rights have been obtained through subleases. Accordingly, a default by our sublessor under the master lease could result in a termination of the master lease by the master lessor, and a corresponding termination of our rights under the sublease. In this event, we would need to obtain a direct lease with the master lessor and there is no assurance we would be able to do so.

You should also note that the operations and maintenance agreements for the projects and the engineering, procurement and construction agreement for the Galena project are with Ormat Nevada. Because Ormat Nevada is our parent and we share management with Ormat Nevada, if Ormat Nevada breaches its obligations under these agreements, we might not enforce our remedies against Ormat Nevada as vigorously as we would if the agreements were with an unrelated third party.

Also, certain other agreements with third parties, including the ConAgra lease and Ormesa project connection and transmission services agreements have specific expiration dates. Formally, the service entitlement under the transmission service agreement with Imperial Irrigation District, or "IID," for the OG II unit at the Ormesa project terminated on December 31, 1990. Although IID has continued to wheel power from the OG II unit to Southern California Edison, and to charge OG II for the service, there can be no assurance that IID will continue to provide transmission service on this basis. If we are unable to enter into replacement agreements with respect to this and other agreements that are scheduled to expire on terms as favorable to us as the existing agreements or at all, we may not be able to meet our obligations under the related power purchase agreements. Failure to perform our obligations under the related power purchase agreements may materially and adversely affect our business, financial condition and operations.

This annual report does not contain historical financial information regarding any party other than us. Therefore, there is no assurance that any third party will be capable of meeting its financial or other responsibilities under its respective agreement(s) with us.

Our Bureau of Land Management leases may be terminated if we fail to comply with any of the
provisions of the Geothermal Steam Act of 1970 or if we fail to comply with the terms or stipulations
of such leases, which may materially and adversely affect our business and operations.

Pursuant to the terms of our Bureau of Land Management (which we refer to as BLM) leases, we are required to conduct our operations on BLM-leased land in a workmanlike manner and in accordance with all applicable laws and BLM directives and to take all mitigating actions required by the BLM to protect the surface of and the environment surrounding the relevant land. Additionally,

certain BLM leases contain additional requirements, some of which relate to the mitigation or avoidance of disturbance of any antiquities, cultural values or threatened or endangered plants or animals, the payment of royalties for timber and the imposition of certain restrictions on residential development on the leased land. In the event of a default under any BLM lease, or the failure to comply with such requirements, or any non-compliance with any of the provisions of the Geothermal Steam Act of 1970 or regulations issued thereunder, the BLM may, 30 days after notice of default is provided to our relevant project subsidiary, suspend operations until the requested action is taken or terminate the lease, either of which could materially and adversely affect our business, operations and financial condition.

Further, certain statutes and regulations, as well as the leases, rights of way and site licenses granted by the BLM, require the BLM, or provide the BLM with discretion, to terminate, not extend, contract, segregate or otherwise reduce or eliminate the right to use BLM lands in connection with the Brady, Mammoth and Ormesa projects.

Some of our leases (or subleases) could terminate if the private lessor (or subleasor) under any such lease (or sublease) defaults on any debt secured by the relevant property, thus terminating our rights to access the underlying geothermal resources at that location.

The fee interest in the land which is the subject of each of our leases (or subleases) may currently be or may become subject to encumbrances securing loans from third party lenders to the lessor (or sublessor). Our rights as lessee (or sublessee) under the leases (or subleases) are or may be subject and subordinate to the rights of any such lender. Accordingly, a default by the lessor (or sublessor) under any such loan could result in foreclosure on the underlying fee interest in the property and thereby terminate our leasehold interest and result in the shutdown of the project located on the relevant property and/or terminate our right of access to the underlying geothermal resources required for our operations. In addition, a default by a sublessor under its lease with the owner of the property that is the subject of our sublease could result in the termination of such lease and thereby terminate our sublease interest and our right to access the underlying geothermal resources required for our operations.

Imperfections in title to our real estate interests may affect our ability to construct or maintain our projects.

The existence of liens, encumbrances and other imperfections in title affecting our real estate interests, could significantly reduce or entirely eliminate the revenues generated by one or more of the projects, which in turn would reduce our net income and could materially and adversely affect our business, operations and financial condition. Other possible imperfections include, without limitation, the rights of third parties to restrict our ability to construct and maintain improvements on, over or under certain property in which they have real estate interests and the possible lack of access rights to certain of the projects. In particular, Brady's access rights over one of the parcels of land used for access to the Desert Peak 1 plant may terminate if Brady does not commence commercial production of geothermal resources from that parcel by 2013. In that event we would need to secure an extension of access rights to that parcel or alternate access to the Desert Peak 1 plant in order to continue operation of the plant.

In addition, although we maintain title insurance for the majority of our plants, and although we reviewed preliminary title reports for each of the plants we did not obtain title opinions or title insurance or confirm pre-existing title insurance on certain of the plants. Therefore, with respect to certain of our plants, title to such assets, and the priority of the mortgage lien to be placed on such assets, has not been verified and there will be no insurance to compensate for any title or lien priority issues in connection with those plants.

We may be unaware of certain adverse aspects of the projects due to our limited history of ownership of the projects.

We recently acquired our interests in some of the projects. In addition, surveys have not been recently conducted for the projects, which mean there may be discrepancies, conflicts in boundary

lines, shortages in area, encroachments or other defects that a correct survey would disclose. Moreover, we have only provided you with title insurance for the properties that are encumbered by deeds of trust in your favor, which means that for the period of time prior to the date (if ever) when such policies are issued for the remaining properties, you (and possibly we) will not have the indemnity, defense or other benefits of a title insurance policy for such properties in the event that an insurable real property loss were to occur. Further, as a result of our limited operating history, it is possible that the projects may not perform as we expect them to or that our operating costs may exceed expectations.

Changes in costs and technology may significantly impact our business by making our power plants less competitive.

A basic premise of our business model is that generating baseload power at central geothermal power plants achieves economies of scale and produces electricity at a competitive price. However, traditional coal-fired systems and gas-fired systems may under certain economic conditions produce electricity at lower average prices than our geothermal plants. In addition, there are other technologies that can produce electricity, most notably fossil fuel power systems, hydroelectric systems, fuel cells, microturbines, windmills and photovoltaic (solar) cells. Some of these alternative technologies currently produce electricity at a higher average price than our geothermal plants; however, research and development activities are ongoing to seek improvements in such alternate technologies and their cost of producing electricity is gradually declining. It is possible that advances will further reduce the cost of alternate methods of power generation to a level that is equal to or below that of most geothermal power generation technologies. If this were to happen, the competitive advantage of our projects may be significantly impaired.

We are subject to risks associated with a changing economic and political environment, which may
adversely affect our financial stability or the financial stability of our counterparties.

The risk of terrorist attacks in the United States or elsewhere continues to remain a potential source of disruption to the nation's economy and financial markets in general. The availability and cost of capital for our business and that of our competitors has been adversely affected by the bankruptcy of Enron Corp. and events related to the California electric market crisis. Additionally, the recent rise in fuel costs may make it more expensive for our customers to operate their businesses. These events could constrain the capital available to our industry and could adversely affect our financial stability and the financial stability of our counterparties in transactions.

We are a holding company and we depend substantially on the performance of our subsidiaries and
the projects they operate, some of which are subject to restrictions and taxation on dividends and
distributions.

We are a holding company whose primary assets are our ownership of the equity interests in our subsidiaries. We conduct no other business and, as a result, we depend entirely upon our subsidiaries' earnings and cash flow.

In the case of some of our projects, such as the Mammoth project, there may be certain additional restrictions on dividend distributions pursuant to our agreements with our partners. This may reduce or eliminate the aggregate amount of cash we can receive from such subsidiaries.

We depend, in the event of the loss of or damage to all or any portion of our projects, upon the sufficiency of our insurance coverage.

The projects are covered by property insurance (including wind, flood and earthquake), business interruption insurance and liability insurance obtained by or for us. Such coverage could prove to be insufficient or an accident or casualty could occur that either is not covered or over which a dispute develops. In addition, there are certain types of losses which are either uninsurable or which are not economically insurable (for example, losses caused by war, nuclear accident, terrorism or

governmental action), or which are otherwise not insured. We cannot assure you that some of the currently available forms of insurance included in the insurance package will continue to be available, or if available, economically feasible for the projects.

The proceeds of insurance for risks that are covered may not be adequate to cover the projects' lost revenues or increased expenses. As a result, if such proceeds are not sufficient, it may adversely and materially affect our business, financial condition and ability to meet our outstanding debt obligations.

We are controlled by Ormat Nevada and its ultimate parent Ormat Industries, and the interests of its shareholders could differ from your interests.

OTec through Ormat Nevada owns 100% of our company and controls us and Ormat Nevada. OTec is in turn controlled by Ormat Industries. Members of our Board of Directors and management, most notably Lucien Bronicki and Yehudit Bronicki, who are also husband and wife, are substantial shareholders of Ormat Industries. Several other Ormat companies have significant business relationships with us, including the operations and maintenance agreements between Ormat Nevada and each of the project companies, and Ormat Nevada regularly purchases equipment and services from other Ormat companies in the course of fulfilling the operations and maintenance agreements. As a result of these relationships, the interests of our management and shareholders may differ from yours and we cannot assure you that better terms would not be provided by firms unaffiliated with the Ormat companies. Our affiliates may also develop other projects that could affect the operation of our projects, as discussed under "—Our exploration, development, and operation of geothermal energy resources is subject to geological risks and uncertainties, which may result in decreased performance and increased costs for our projects."

In addition, two of our three directors are directors and/or officers of OTec and Ormat Industries. These directors will have fiduciary duties to all three companies and may have conflicts of interest on matters affecting both us and our parent and in some circumstances may have interests adverse to our interests.

Distributions to us from the Mammoth project are subject to the provisions of the Mammoth-Pacific, L.P. limited partnership agreement and may not be available to us as expected.

The Mammoth-Pacific, L.P. limited partnership agreement provides that any cash distributions shall be made to us and Constellation Energy Group only after payment of all debt service and other expenses of Mammoth-Pacific, L.P. , satisfaction of Mammoth-Pacific, L.P. 's liabilities as they become due and the establishment of and contributions to reserves that we and Constellation Energy Group may from time to time reasonably determine to be appropriate. Any cash distributions shall be made at the times and in the amounts determined jointly by us and Constellation Energy Group, but not less often than annually and, if practicable and not otherwise prohibited, within 30 days after the close of each fiscal quarter. If cash distributions to us cannot be made in sufficient amounts or with the necessary frequency, our financial condition may be materially and adversely affected.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information responding to Item 7A is filed with this annual report under Part II Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations."

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


Consolidated Financial Statements of Ormat Funding Corp. and Subsidiaries
Report of Independent Registered Public Accounting Firm					56
Consolidated Financial Statements as of December 31, 2004, and 2003 and for each of the three years in the period ended December 31, 2004:
Consolidated Balance Sheets					57
Consolidated Statements of Operations					58
Consolidated Statements of Stockholders' Equity					59
Consolidated Statements of Cash Flows					60
Notes to Consolidated Financial Statements					61
Financial Statements of OrMammoth Inc. ⁽¹⁾
Report of Independent Auditors					81
Financial Statements as of December 31, 2004 and 2003, and for the year ended December 31, 2004 and for the period from November 10, 2003 (Date of Incorporation) to December 31, 2003:
Balance Sheets					82
Statements of Operations					83
Statements of Stockholder's Equity					84
Statements of Cash Flows					85
Notes to Financial Statements					86
Financial Statements of Mammoth-Pacific, L.P. ⁽²⁾
Report of Independent Auditors					90
Financial Statements as of December 31, 2004, and 2003 and for each of the three years in the period ended December 31, 2004:
Balance Sheets					91
Statements of Operations					92
Statements of Partners' Capital					93
Statements of Cash Flows					94
Notes to Financial Statements					95


(1)	As the collateral for the Senior Secured Notes includes a pledge by the Company of all of the capital stock of OrMammoth Inc. owned by the Company, separate financial statements of OrMammoth Inc. have been included pursuant to Rule 3-16 of Regulation S-X.


(2)	As the Company's 50% ownership interest in Mammoth-Pacific, L.P. is accounted for by the equity method, separate financial statements of Mammoth-Pacific, L.P. have been included pursuant to Rule 3-09 of Regulation S-X.

Ormat Funding Corp.
and Subsidiaries

(a wholly owned subsidiary of Ormat Nevada, Inc.)

Report on Audits of
Consolidated Financial Statements
As of December 31, 2004 and 2003, and for the three
years in the period ended December 31, 2004

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of
Ormat Funding Corp.

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of stockholder's equity and of cash flows present fairly, in all material respects, the financial position of Ormat Funding Corp. and its subsidiaries (a wholly owned subsidiary of Ormat Nevada, Inc.) at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 8 to the financial statements, effective January 1, 2003, the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, Accounting for Obligations Associated with the Retirement of Long-Lived Assets.

/s/ PricewaterhouseCoopers LLP

Sacramento, California
March 21, 2005

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

CONSOLIDATED BALANCE SHEETS


	December 31,
	2004		2003
	(dollars in thousands)
Assets
Current assets:
Cash	$	3	$	3
Restricted cash and cash equivalents		31		1,584
Accounts receivable		7,404		6,050
Prepaid expenses and other		41		323
Total current assets		7,479		7,960

Restricted cash and cash equivalents		19,339		—
Investment in Partnership		36,361		38,772
Deposits and other		2,850		550
Property, plant and equipment, net		142,468		75,590
Construction-in-process		6,823		1,625
Deferred financing costs, net		9,582		2,445
Intangible assets, net		10,281		6,777
Total assets	$	235,183	$	133,719
Liabilities and Stockholder's Equity
Current liabilities:
Accounts payable and accrued expenses	$	7,064	$	7,720
Current portion of long-term debt		6,090		3,857
O&M payable to Parent		4,318		3,447
Total current liabilities		17,472		15,024
Long-term debt, net of current portion		183,399		11,617
Long-term subordinated loan from Parent		8,216		86,024
Deferred income taxes		6,052		5,083
Asset retirement obligation		5,429		3,029
Total liabilities		220,568		120,777
Commitments and contingencies (Note 12)
Stockholder's equity:
Common stock, par value $1 per share; 1,000 shares authorized; 500 shares issued and outstanding		1		1
Retained earnings		14,614		12,941
Total stockholder's equity		14,615		12,942
Total liabilities and stockholder's equity	$	235,183	$	133,719

The accompanying notes are an integral part of these financial statements.

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

CONSOLIDATED STATEMENTS OF OPERATIONS


	Year Ended December 31,
	2004			2003			2002
	(dollars in thousands)
Revenues:
Energy and capacity	$	48,071		$	41,885		$	31,451
Lease portion of energy and capacity		9,556			—			—
Total revenues		57,627			41,885			31,451
Cost of revenues (Note 11):
Energy and capacity		33,532			30,387			22,126
Lease portion of energy and capacity		4,409			—			—
Total cost of revenues		37,941			30,387			22,126
Gross margin		19,686			11,498			9,325
General and administrative expenses		1,706			1,268			775
Operating income		17,980			10,230			8,550
Other income (expense):
Interest income		567			23			1
Interest expense		(18,310	)		(1,994	)		—
Other non-operating income		50			112			72
Income before income taxes and equity in income of investee		287			8,371			8,623
Income tax provision		(74	)		(2,132	)		(2,734	)
Equity in income of investee		1,460			141			—
Income before cumulative effect of change in accounting principle		1,673			6,380			5,889
Cumulative effect of change in accounting principle (net of tax benefit of $125,000)		—			(205	)		—
Net income	$	1,673		$	6,175		$	5,889

The accompanying notes are an integral part of these financial statements.

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY


	Common Stock
	Shares		Amount		Retained Earnings		Total
			(dollars in thousands)
Balance at December 31, 2001		500	$	1	$	877	$	878
Net income		—		—		5,889		5,889
Balance at December 31, 2002		500		1		6,766		6,767
Net income		—		—		6,175		6,175
Balance at December 31, 2003		500		1		12,941		12,942
Net income		—		—		1,673		1,673
Balance at December 31, 2004		500	$	1	$	14,614	$	14,615

The accompanying notes are an integral part of these financial statements.

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2004			2003			2002
	(dollars in thousands)
Cash flows from operating activities:
Net income	$	1,673		$	6,175		$	5.889
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		9,095			4,861			2,687
Amortization		2,917			1,055			362
Accretion of asset retirement obligation		303			224			—
Equity in income of investee		(1,460	)		(141	)		—
Distributions from Partnership		2,140			—			—
Deferred income tax provision		74			2,132			2.622
Cumulative effect of change in accounting principle		—			205
Accrued interest on long-term subordinated loan from Parent		1,295			199			—
Changes in operating assets and liabilities, net of acquisition:
Accounts receivable		591			(439	)		(4,413	)
Prepaid expenses and other		282			(261	)		(62	)
Deposits and other		—			(550	)		—
Accounts payable and accrued expenses		(2,111	)		4,998			(1,170	)
Payable to Parent for operating activities		871			1,570			(110	)
Net cash provided by operating activities		15,670			20,028			5,805
Cash flows from investing activities:
Change in restricted cash and cash equivalents		(17,974	)		1,032			(2,616	)
Capital expenditures		(9,601	)		(16,994	)		(4,746	)
Distributions from Partnership		2,627			—			—
Deposits and other		(2,063	)		—			—
Cash paid for acquisition		(74,366	)		—			—
Net cash used in investing activities		(101,377	)		(15,962	)		(7,362	)
Cash flows from financing activities:
Borrowings from Parent for capital expenditures		43,654			1,624			—
Long-term subordinated loan from Parent		—			3,637			983
Repayment of long-term subordinated loan from Parent		(122,759	)		(3,372	)		(17,834	)
Proceeds from issuance of long-term debt		190,000			—			20,000
Repayments of long-term debt		(15,985	)		(4,527	)		—
Deferred debt issuance costs		(9,203	)		(1,428	)		(1,593	)
Net cash provided by (used in) financing activities		85,707			(4,066	)		1,556
Net increase (decrease) in cash		—			—			(1	)
Cash at beginning of year		3			3			4
Cash at end of year	$	3		$	3		$	3
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest, net of amount capitalized	$	14,611		$	1,220		$	—
Income taxes	$	—		$	—		$	1
Supplemental non-cash investing and financing activities:
Purchase of Ormesa assets, and incurrence of long-term subordinated loans from Parent	$	—		$	—		$	41,700
Transfer of Desert Peak assets from Parent and incurrence of long-term subordinated loan from Parent	$	—		$	—		$	2,500
Transfer of ORNI 7 (including Steamboat Geothermal) and 50% interest in Mammoth from Parent and incurrence of long-term subordinated loan from Parent	$	—		$	39,847		$	—
Effect of adopting SFAS No. 143 (Note 8):
Asset retirement costs	$	1,156		$	2,475		$	—
Asset retirement obligations	$	1,156		$	2,805		$	—

The accompanying notes are an integral part of these financial statements.

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 — BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Business

Ormat Funding Corp. ("OFC") and subsidiaries (the "Company"), a wholly owned subsidiary of Ormat Nevada, Inc. (the "Parent"), is engaged in the ownership and operation of geothermal power plants in Southern California and Nevada, United States of America ("U.S".). The Parent is a wholly owned subsidiary of Ormat Technologies, Inc. (the "U.S. Parent"), which in turn is a subsidiary of Ormat Industries Ltd. (the "Ultimate Parent").

Several of the Company's power plant facilities are listed as Qualifying Facilities ("QF") under the Public Utility Regulatory Policies Act ("PURPA"). The related power purchase agreements for such facilities are dependent upon the Company maintaining the QF status. Management believes that all of the facilities were in compliance with the QF status as of December 31, 2004.

Rounding

Dollar amounts, except per share data, in the notes to these financial statements are rounded to the closest $1,000.

Basis of presentation

As further discussed in Note 2, on June 29, 2001, all the ownership interests in Brady Power Partners ("BPP") were acquired 50% by ORNI 1 LLC ("ORNI 1"), and 50% by ORNI 2 LLC ("ORNI 2"), both wholly owned subsidiaries of the Parent for a purchase price of $19.7 million. Also, as further discussed in Note 2, on June 30, 2003, the Parent, through ORNI 7 LLC ("ORNI 7"), a wholly owned subsidiary of the Parent acquired Steamboat Geothermal LLC ("SG"), and On December 18, 2003, the Parent acquired a 50% ownership interest in Mammoth-Pacific, L.P. ("Mammoth"). The Company was incorporated in Delaware on December 19, 2001. On July 10, 2002 and December 8, 2003, the Parent contributed its ownership interests in ORNI 1 and ORNI 2, and in ORNI 7, respectively, to the Company at net book value, and on January 30, 2004, the Parent contributed its 50% ownership interest in Mammoth at net book value to OrMammoth Inc. ("OrMammoth"), a wholly owned subsidiary of the Company. Such transfers have been accounted for as entities under common control in a manner similar to a pooling of interests of entities, and have been reflected in these financial statements as having occurred as of the respective purchase dates. Prior to the acquisition of ownership interests in BPP, SG and Mammoth, ORNI 1, ORNI 2, ORNI 7 and OrMammoth were dormant entities.

Also as further discussed in Note 2, on April 15, 2002, the Company, through Ormesa LLC ("Ormesa"), a wholly owned subsidiary, acquired the Ormesa project, and on February 11, 2004, the Company, through ORNI 7, acquired the Steamboat 2/3 project. The operating results related to the Ormesa and the Steamboat 2/3 projects have been included in these consolidated financial statements beginning April 15, 2002 and February 11, 2004, respectively.

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries: ORNI 1, ORNI 2, ORNI 7, Ormesa and OrMammoth. All intercompany accounts and transactions are eliminated.

The Company accounts for its interests in partnerships and companies in which it has equal to or less than 50% ownership interest under the equity method. Under the equity method, original investments are recorded at cost and adjusted by the Company's share of undistributed earnings or losses of such companies. The Company's earnings in investments accounted for under the equity method have been reflected as "Equity in income of investee" on the Company's consolidated statements of operations.

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cash

Cash consists of deposit accounts with banks.

Restricted cash and cash equivalents

Under the terms of certain long-term debt agreements, the Company is required to maintain certain debt service reserve, cash collateral and operating fund accounts that have been classified as restricted cash and cash equivalents. Funds that will be used to satisfy obligations due during the next twelve months are classified as current restricted cash and cash equivalents, with the remainder classified as non-current restricted cash and cash equivalents. Such amounts are invested primarily in money market accounts. The Company considers all highly liquid instruments, with an original maturity of three months or less, to be cash equivalents.

Certain of the restricted cash accounts can be replaced by a letter of credit, and as further discussed in Note 12, on July 1, 2004 and December 30, 2004, a letter of credit in the total amount of approximately $10.8 million was issued by the Parent, on behalf of the Company, to release restriction on funds that were used as a pledge against the Company's 8¼% senior secured notes (see Note 6).

Concentration of credit risk

Financial instruments which potentially subject the Company to concentration of credit risk consist principally of temporary cash investments and accounts receivable.

The Company places its temporary cash investments with high credit quality financial institutions located in the U.S. At December 31, 2004 and 2003, the Company had deposits in one and four, respectively, U.S. financial institutions that were federally insured up to $100,000 per financial institution.

All of the Company's revenues, and the related receivable balances, are earned from two power companies: Southern California Edison ("SCE") and Sierra Pacific Power Company ("SPPC"). Revenues from SCE and SPPC for the years ended December 31, 2004, 2003 and 2002 amounted to 54% and 46%, 73% and 27% and 69% and 31%, respectively. The Company performs ongoing credit evaluations of its customers' financial condition. The Company has historically been able to collect on substantially all of its receivable balances, and accordingly, no provision for doubtful accounts has been made.

Deposits and other

Deposits and other consist primarily of performance bonds for construction projects, as well as a deposit held for certain real property near the Steamboat facilities ("Meyberg Property"). As further discussed in Note 11, the deposit is associated with a lease agreement ("Meyberg Lease") granting the right to develop certain land identified in the lease for the purpose of expanding the Company's geothermal assets and resources.

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Property, plant and equipment

Property, plant and equipment are stated at cost. All costs associated with the acquisition, development and construction of power plant facilities are capitalized. Major improvements are capitalized, and repairs and maintenance costs are expensed. Power plants are depreciated using the straight-line method over the term of the relevant power purchase agreement (see Note 9). The other assets are depreciated using the straight-line method over the following estimated useful lives of the assets:

The cost and accumulated depreciation of items sold or retired are removed from the accounts. Any resulting gain or loss is recognized currently and is recorded in operating income.

The Company capitalizes interest costs as part of constructing power plant facilities. Such capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset's estimated useful life. Capitalized interest costs amounted to $132,000 for the year ended December 31, 2004. There were no capitalized interest costs for the years ended December 31, 2003 and 2002.

Deferred financing costs

Deferred financing costs are amortized over the term of the related obligation using the effective interest method. Amortization of deferred financing costs is presented as interest expense in the statement of operations. Accumulated amortization related to deferred financing costs amounted to approximately $1,019,000 and $576,000 at December 31, 2004 and 2003, respectively. Amortization expense for the years ended December 31, 2004, 2003 and 2002 amounted to $2,017,000, $576,000 and $0, respectively.

Intangible assets

Intangible assets consist of allocated acquisition cost of power purchase agreements, which are amortized over the 15 to 21-year terms of the agreements using the straight-line method.

Impairment of long-lived assets and long-lived assets to be disposed of

Long-lived assets including unconsolidated investments and power purchase agreements are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net undiscounted cash flow expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. Management believes that no impairment exists for long-lived assets, however, future estimates as to the recoverability of such assets may change based on revised circumstances.

Derivative instruments

Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted by other related accounting literature, establishes accounting and reporting standards for derivative instruments (including certain derivative

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

instruments embedded in other contracts). SFAS No. 133 requires companies to record derivatives on their balance sheets as either assets or liabilities measured at their fair value unless exempted from derivative treatment as a normal purchase and sale. All changes in the fair value of derivatives are recognized currently in earnings unless specific hedge criteria are met, which requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.

The Company is subject to the provisions of SFAS No. 133 Derivative Implementation Group ("DIG") Issue No. C15, Normal Purchases and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity, which expands the requirements for the normal purchase and normal sales exception to include electricity contracts entered into by a utility company when certain criteria are met. Also under DIG Issue No. C15, contracts that have a price adjustment clause based on an index that is not directly related to the electricity generated, as defined in SFAS No. 133, do not meet the requirements for the normal purchases and normal sales exception. The Company has power sales agreements that qualify as derivative instruments under DIG Issue No. C15 because they have a price adjustment clause based on an index that does not directly relate to the sources of the power used to generate the electricity. The adoption of the provisions of DIG Issue No. C15 in 2002 did not have a material impact on the Company's consolidated financial position and results of operations.

In June 2003, the Financial Accounting Standards Board ("FASB") issued DIG Issue No. C20, Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature. DIG Issue No. C20 superseded DIG Issue No. C11, Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception, and specified additional circumstances in which a price adjustment feature in a derivative contract would not be an impediment to qualifying for the normal purchases and normal sales scope exception under SFAS No. 133. DIG Issue No. C20 was effective as of the first day of the fiscal quarter beginning after July 10, 2003, (i.e. October 1, 2003, for the Company). In conjunction with initially applying the implementation guidance, DIG Issue No.C20 requires contracts that did not previously qualify for the normal purchases normal sales scope exception, and do qualify for the exception under DIG Issue No. C20, to freeze the fair value of the contract as of the date of the initial application, and amortize such fair value over the remaining contract period. Upon adoption of DIG Issue No. C20, the Company elected the normal purchase and normal sales scope exception under SFAS No. 133 related to its power purchase agreements. Such adoption did not have a material impact on the Company's consolidated financial position and results of operations.

Revenues

Revenues related to the sale of electricity from geothermal power plants and capacity payments are recorded based upon output delivered and capacity provided at rates specified under relevant contract terms. As described below, for power purchase agreements ("PPAs") acquired as part of the projects purchased since July 1, 2003 (see Note 2), revenues related to the lease element of the PPA are included as "lease portion of energy and capacity" revenues, with the remaining revenues related to the production and delivery of energy presented as "energy and capacity".

In May 2003, the Emerging Issues Task Force ("EITF") reached consensus in EITF Issue No. 01-8, Determining Whether an Arrangement Contains a Lease, to clarify the requirements of identifying whether an arrangement contains a lease at its inception. The guidance in the consensus is designed to broaden the scope of arrangements, such as power purchase agreements, accounted for as leases. EITF Issue No. 01-8 requires both parties to an arrangement to determine whether a service contract or similar arrangement is, or includes, a lease within the scope of SFAS No. 13, Accounting for Leases. The consensus is being applied prospectively to arrangements agreed to, modified, or acquired in

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

business combination on or after July 1, 2003. The adoption of EITF Issue No. 01-8 effective July 1, 2003 did not have a material effect to the Company's financial position or results of operations. As further discussed in Note 9, the PPA acquired as part of the Steamboat 2/3 project which was purchased since July 1, 2003, contains lease elements within the scope of SFAS No. 13.

Income taxes

The Company is included in the U.S. Parent's consolidated federal and state tax returns as an affiliated group. Income taxes are accounted for by the Company using the separate return method pursuant to SFAS No. 109, Accounting for Income Taxes. Under SFAS No. 109, the Company uses the asset and liability approach, which requires the recognition of taxes payable or refundable for the current year and deferred tax assets and liabilities for the future tax consequences of events that have been recognized in the Company's financial statements or tax returns. The measurement of current and deferred tax assets and liabilities are based on provisions of the enacted tax law; the effects of future changes in tax laws or rates are not anticipated. The Company accounts for investment tax credits as a reduction to income taxes in the year in which the credit arises. The measurement of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that, based on available evidence, are not expected to be realized. The current income taxes payable/receivable are recorded in amounts due to/from Parent as the Company settles such obligations currently.

Fair value of financial instruments

The carrying amount of restricted cash and cash equivalents approximates fair value because of the short maturity of those instruments. The fair value of long-term debt is estimated based on the current borrowing rates for similar issues, and for the senior secured notes (see Note 6) such fair value amounted to approximately $191.9 million compared to carrying amount of $189.5 million at December 31, 2004.

Accounting estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of such financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

New accounting pronouncements

FIN No. 46R — Consolidation of Variable Interest Entities

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, which was revised in December 2003 ("FIN No. 46R"). FIN No. 46R clarifies the application of Accounting Research Bulleting No. 51, Consolidated Financial Statements, and applies immediately to any variable interest entities created after December 31, 2003, and to variable interest entities in which an interest is obtained after that date. Effective March 31, 2004, the Company adopted the provisions of FIN No. 46R, which did not have an impact on its consolidated results of operations and financial position.

SFAS No. 153 — Exchange of Nonmonetary Assets

In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets — An Amendment of APB Opinion No. 29. SFAS No. 153 amends APB Opinion No. 29, Accounting for

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Nonmonetary Transactions. The amendments made by SFAS No. 153 are based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Further, the amendments eliminate the exception for nonmonetary exchanges of similar productive assets and replace it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. The provisions in SFAS No. 153 are effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005 (July 1, 2005 for the Company). Early application of SFAS No. 153 is permitted. The provisions of SFAS No.153 shall be applied prospectively. The Company does not expect SFAS No.153 to have a material impact on its results of operations and financial position in future periods.

EITF Issue No. 02-14 — Whether an Investor Should Apply the Equity Method of Accounting to Investments Other Than Common Stock

In July 2004, the FASB issued EITF Issue No. 02-14, Whether an Investor Should Apply the Equity Method of Accounting to Investments Other Than Common Stock. EITF Issue No. 02-14 addresses whether the equity method of accounting applies when an investor does not have an investment in voting common stock of an investee but exercises significant influence through other means. EITF Issue No. 02-14 states that an investor should only apply the equity method of accounting when it has investments in either common stock or in-substance common stock of the investee, provided that the investor has the ability to exercise significant influence over the operating and financial policies of the investee. The provisions in EITF Issue No. 02-14 are effective for reporting periods beginning after September 15, 2004 (October 1, 2004 for the Company). The adoption of EITF Issue No. 02-14 by the Company did not have any impact on its results of operations and financial position.

NOTE 2 — BUSINESS ACQUISITIONS

The Brady Project – Brady Power Partners ("BPP")

The net assets of Brady Power Partners, a Nevada general partnership that owns a geothermal power plant in Nevada, were acquired on June 29, 2001, by subsidiaries of the Parent and such subsidiaries were transferred to the Company on July 10, 2002. This acquisition was accounted for under the purchase method of accounting. The acquired assets are being depreciated over their estimated useful lives of five to twenty one years.

The Ormesa Project

On April 15, 2002, the Company acquired 100% interests in the Ormesa Project, located in Imperial Valley, California, to expand its geothermal power plant operations. The Ormesa Project consists of six power plants and was owned by several unrelated companies. The Company acquired 100% interests in four entities and acquired the assets of a fifth entity. These entities and assets were merged into Ormesa, LLC ("Ormesa") in 2002. The Company paid approximately $41.7 million for the ownership of the Ormesa Project, of which approximately $35.7 million and $6.0 million has been allocated to property, plant, and equipment and intangible assets, respectively. The acquisition was accounted for under the purchase method of accounting and the acquired assets are being depreciated over their estimated useful lives of five to fifteen years. The results of operations of the Ormesa Project have been included in the consolidated financial statements since April 15, 2002.

The Steamboat Projects

On June 30, 2003, the Company acquired from two groups of unrelated sellers, a 100% interest in Steamboat Geothermal LLC ("SG"), which owns geothermal power plants ("Steamboat 1/1A") in

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Nevada. The purchase price of approximately $1.2 million was paid in cash, of which, $2.1 million has been recorded as property, plant and equipment, less assumption of liabilities of $0.9 million. The acquisition has been accounted for under the purchase method of accounting and the acquired assets are being depreciated over their estimated useful lives of three to fifteen years. The results of operations of the Steamboat 1/1A Project have been included in the consolidated financial statements since July 1, 2003.

On February 11, 2004, the Company acquired 100% of the outstanding shares of capital stock of Steamboat Development Corp. ("SDC") from an unrelated party. SDC owned certain leasehold interests as a lessee in the two Steamboat 2/3 geothermal power plants and certain related geothermal leases. On February 13, 2004, the Company acquired all of the beneficial rights, title, and interest in the Steamboat 2/3 geothermal power plants from the lessor. The Company acquired SDC to increase its geothermal power plant operations in the United States. The Company acquired the lessee and lessor positions of the Steamboat 2/3 geothermal power plants for a combined purchase price of approximately $73.6 million, plus transaction cost of approximately $0.8 million. The acquisition has been accounted for under the purchase method of accounting and the acquired assets and intangibles, are being depreciated over their estimated useful lives of approximately 19 years. The purchase price of the lessee and lessor position has been allocated based on an independent valuation and management's estimates. The results of the Steamboat 2/3 Project's operations have been included in the consolidated financial statements since February 11, 2004.

Net assets transferred to or purchased by the Company have been allocated as follows:


	Brady Project			Ormesa Project		Steamboat 1/1A Project			Steamboat 2/3 Project
	(dollars in thousands)
Property, plant and equipment	$	20,378		$	35,695	$	2,138		$	70,319
Power purchase agreements		1,652			6,005		—			4,499
Accounts receivable assumed		919			—		—			1,944
Accrued liabilities assumed		(3,277	)		—		(923	)		(1,455	)
Asset retirement obligation		—			—		—			(941	)
Total cash paid	$	19,672		$	41,700	$	1,215		$	74,366

The following unaudited pro forma financial information for the years ended December 31, 2004 and 2003, assumes the Steamboat 2/3 Project acquisition occurred on January 1, 2003. The pro forma results include: (i) the elimination of interest expense related to the Steamboat 2/3 Project's finance lease agreement that was terminated as part of the acquisition of the lessee and lessor interests and, (ii) the change in depreciation and amortization resulting from the step-up in basis of property, plant and equipment and power purchase agreements of approximately $29.5 million and $4.5 million, respectively. The pro forma results are not necessarily indicative of what the actual results of operations would have been had the acquisition been completed on January 1, 2003, nor are they necessarily indicative of future consolidated results.


	Year Ended December 31,
	2004		2003
	(dollars in thousands)
Revenues	$	59,569	$	56,208
Income before cumulative effect of accounting change		2,270		9,613
Net income		2,270		9,408

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Mammoth Project

On December 18, 2003, the Parent acquired a 50% ownership interest in Mammoth-Pacific, LP ("Mammoth"), which is comprised of three geothermal power plants, with a combined generating capacity of 25 MW, located near the city of Mammoth, California ("Mammoth Project"). On January 30, 2004, the Parent transferred the ownership interest in Mammoth to the Company at net book value, which approximated $38.8 million at December 31, 2003. As this was a transfer between entities under common control, the December 31, 2003 balance sheet reflects the investment in partnership balance of approximately $38.8 million, an increase in the long-term subordinated loan from Parent by $38.6 million, and an increase in the retained earnings by $0.1 million related to the Company's equity in the earnings of Mammoth for the period from December 18, 2003 to December 31, 2003.

The purchase price was less than the underlying net equity of Mammoth by approximately $9.3 million. As such, the basis difference will be amortized over the remaining useful life of the property, plant and equipment and the power purchase agreements, which range from 12 to 17 years. The Company's 50% ownership interest in Mammoth is accounted for under the equity method of accounting as the Company has the ability to exercise significant influence, but not control, over Mammoth.

The condensed financial position and results of operations of Mammoth are summarized below:


	December 31,
	2004		2003
	(dollars in thousands)
Condensed balance sheets:
Current assets	$	11,088	$	11,182
Non-current assets		83,944		88,918
Current liabilities		924		608
Non-current liabilities		3,774		3,680
Partners' equity		90,334		95,812


	Year Ended December 31, 2004			Period from December 18, 2003 to December 31, 2003
	(dollars in thousands)
Condensed statements of operations:
Net sales	$	15,815		$	672
Gross margin*		3,830			252
Net income		3,521			246
* Including depreciation expenses		5,605			223

Company's equity in income of Mammoth:
50% of Mammoth net income	$	1,761		$	123
Plus amortization of the equity basis difference		593			18
		2,354			141
Less income taxes		(894	)		—
Total	$	1,460		$	141

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The unaudited pro forma equity in income of Mammoth for the years ended December 31, 2003 and 2002, assuming the acquisition of the 50% ownership interest in Mammoth occurred on January 1, 2002, would have been $1,140,000 and $1,474,000, respectively.

Effective December 18, 2003, the Parent operates and maintains the Mammoth project under an Operation and Maintenance ("O&M") agreement. The amount of O&M expenses paid during the year ended December 31, 2004 were $1,822,000.

NOTE 3 — PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, consists of the following:


	December 31,
	2004			2003
	(dollars in thousands)
Land	$	1,756		$	—
Machinery and equipment		309			301
Office equipment		542			542
Automobiles		73			14
Geothermal power plants, including geothermal wells		152,344			80,292
Asset retirement cost		4,713			2,615
		159,737			83,764
Less accumulated depreciation		(17,269	)		(8,174	)
Total	$	142,468		$	75,590

Depreciation expense for the years ended December 31, 2004, 2003 and 2002 amount to $9,095,000, $4,861,000 and $2,687,000, respectively.

NOTE 4 — INTANGIBLE ASSETS

Intangible assets consist of all of the Company's power purchase agreements acquired in business combinations and amounted to $10,281,000 and $6,777,000 net of accumulated amortization of $1,781,000 and $881,000 as of December 31, 2004 and 2003, respectively.

Amortization expense for the years ended December 31, 2004, 2003 and 2002 amount to $900,000, $479,000 and $362,000, respectively.

Estimated future amortization expense for the intangible assets as of December 31, 2004 is as follows:


Year ending December 31:	(dollars in thousands)
2005	$	824
2006		824
2007		824
2008		824
2009		824
Thereafter		6,161
Total	$	10,281

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5 — ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Accounts payable and accrued expenses consist of the following:


	December 31,
	2004		2003
	(dollars in thousands)
Trade payables	$	—	$	44
Scheduling and transmission charges		3,505		3,684
Debt issuance costs		—		1,313
Other		3,559		2,679
Total	$	7,064	$	7,720

NOTE 6 — LONG-TERM DEBT

Long-term debt consists of the following:


	December 31,
	2004			2003
	(dollars in thousands)
Ormesa loan	$	—		$	15,474
Senior secured notes		189,489			—
		189,489			15,474
Less current portion		(6,090	)		(3,857	)
	$	183,399		$	11,617

Ormesa loan

On December 31, 2002, a wholly owned subsidiary of the Company ("Ormesa LLC"), that owns and operates the Ormesa Complex, entered into a senior secured credit facility agreement ("Ormesa Loan") amounting to $20 million with a bank. On December 31, 2004, Ormesa LLC repaid this loan in its entirety.

Senior secured notes

On February 13, 2004, the Company completed the issuance of 8¼% senior secured notes (the "Notes") pursuant to an exempt offering under Rule 144A and Regulation S of the Securities Act of 1933, as amended ( the "Offering"), amounting to $190 million, and received net cash proceeds of approximately $179.7 million after deduction of deferred bond issuance costs of approximately $10.3 million, which have been included in deferred financing costs at December 31, 2004. The Notes have a final maturity date of December 30, 2020. Principal and interest on the Notes are payable in semi-annual payments that commenced on June 30, 2004. The Notes are collateralized by substantially all of the assets of the Company and fully and unconditionally guaranteed by all of the wholly owned subsidiaries of the Company, and (with certain exceptions) by all real property, contractual rights, revenues and bank accounts, intercompany notes, certain insurance policies and guarantees of the Company. There are various restrictive covenants under the Notes, which include limitations on additional indebtedness and payment of dividends. As of December 31, 2004, management believes that the Company was in compliance with the covenants under the Notes.

The Company may redeem the Notes, in whole or in part, at any time at redemption price equal to the principal amount of the Notes to be redeemed plus accrued interest, premium and liquidated

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

damages, if any, plus a "make-whole" premium. Upon certain events, as defined in the note agreement, the Company may be required to redeem a portion of the Notes at a redemption price ranging from 100% to 101% of the principal amount of the Notes being redeemed plus accrued interest, premium and liquidated damages, if any.

A registration statement on Form S-4 relating to the Notes was filed with and declared effective by the Securities and Exchange Commission on February 9, 2005. Pursuant to the registration statement, the Company made an offer to the holders of the Notes to exchange them for publicly registered exchange notes with substantially identical terms until March 11, 2005. On March 16, 2005 the exchange offer was completed.

Non-current restricted cash at December 31, 2004 relating to proceeds from the Offering consists of the following:

Galena project construction reserve

As required under the terms of the Notes, the Company was required to set aside approximately $25.8 million ($19.4 million at December 31, 2004) to replace the existing equipment at the Steamboat 1/1A project with more efficient equipment, in order to optimize the geothermal resources available. After such replacement, the Company will rename the Steamboat 1/1A project as the Galena project. The Company expects that the Galena project will be complete achieve commercial operations by the end of 2005.

Also as required under the terms of the Notes, the Company has restricted cash accounts, consisting of the following, which are classified as current on the balance sheet:

Debt service reserve

The Company maintains an account to fund an amount sufficient to pay scheduled debt service amounts, including principal and interest, due under the terms of the Notes in the following six months. As of December 31, 2004 the restricted cash accounts have been replaced by a letter of credit which was issued by the Parent, on behalf of the Company on July 1, 2004 and December 30, 2004 in the total amount of approximately $10.8 million (see Note 12).

Revenue reserve

The Company deposits all revenues received into the revenue account. Such amounts are used to pay operating expenses and fund the debt service reserve account, but the funds are only available to the Company upon submission of draw requests by the Company to the bank. As such amounts are not fully unrestricted to use by the Company, they have been classified as restricted in the balance sheets. As of December 31, 2004, the balance of such account was $0.

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Future minimum payments

Future minimum payments under the Notes as of December 31, 2004 are as follows:


Year ending December 31:	(dollars in thousands)
2005	$	6,090
2006		9,611
2007		8,932
2008		7,835
2009		9,140
Thereafter		147,881
Total	$	189,489

The payment obligation under the Notes are guaranteed by ORNI 1 LLC ("ORNI 1"), ORNI 2 LLC ("ORNI 2"), ORNI 7 LLC ("ORNI 7"), OrMammoth Inc. ("OrMammoth"), and Ormesa LLC ("Ormesa"), all wholly owned subsidiaries of the Company, as of December 31, 2004. Prior to December 31, 2004, Ormesa was not a guarantor of the Notes, and effective December 31, 2004, upon the repayment of the Ormesa Loan in its entirety, Ormesa executed a guarantee of the Notes and granted a first priority lien on the Ormesa project and all other Ormesa assets in favor of the collateral agent for the benefit of the holders of the Notes. Such guarantees are full, unconditional and joint and several. The Company's sole purpose is to hold 100% ownership interest in ORNI 1, ORNI 2, ORNI 7, Ormesa, and OrMammoth, and the Company does not have any independent assets or operations. ORNI 1 and ORNI 2's sole purpose is to each hold a 50% ownership interest in Brady Power Partners. ORNI 7's sole purpose is to hold 100% ownership interest in Steamboat Geothermal LLC and Steamboat Development Corp. OrMammoth's sole purpose is to hold a 50% ownership interest in Mammoth-Pacific L.P.

NOTE 7 — LONG-TERM SUBORDINATED LOAN FROM PARENT

As a result of previous acquisitions (see Note 2), the Company incurred debt to the Parent. In addition, costs incurred by the Company for major capital expansion are paid by the Parent and billed to the Company under the same debt agreement. Prior to December 1, 2003, all amounts owed to the Parent were interest free and payable from available cash, as defined. On December 1, 2003, the Company entered into a loan agreement with the Parent pursuant to which the Company may borrow up to $55 million from time to time. The loan is due in 2021 and is payable only from available cash flow, is subordinated to other debt and has been classified as non-current. Interest accrues on the unpaid principal of the loan amount at a rate per annum equal to the higher of 5% or the applicable Federal rate (4.68% and 5.12% at December 31, 2004 and 2003, respectively), and is added to the principal and is also due in 2021 or from available cash flow, as defined. Interest expense incurred under the loan agreement with the Parent amounted to $1,295,000 and $199,000 during the years ended December 31, 2004 and 2003, respectively.

NOTE 8 — ASSET RETIREMENT OBLIGATION

The Company adopted SFAS No. 143, Accounting for Obligations Associated with the Retirement of Long-Lived Assets, effective January 1, 2003. Under SFAS No. 143, entities are required to record the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. The Company's legal liabilities include capping wells and post-closure costs of geothermal power producing sites. When a new liability for asset retirement obligations is recorded, the Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset.

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. At retirement, an entity settles the obligation for its recorded amount or incurs a gain or loss. On January 1, 2003, the Company recorded a cumulative effect of change in accounting principle of $205,000 net of related tax benefit of $125,000.

The following table presents a reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligation for the years presented:


	Year Ended December 31,
	2004		2003
	(dollars in thousands)
Balance at beginning of year	$	3,029	$	2,805
Liabilities incurred		941		—
Change in prior estimates		1,156		—
Accretion expense		303		224
Balance at end of year	$	5,429	$	3,029

During the fourth quarter of 2004 the Company increased the aggregate carrying amount of their asset retirement obligation by $1,156,600. The increase is a result of increased costs associated with drilling rigs, cement and certain services, general manpower, engineering fees and other outside services, since the adoption of SFAS No. 143.

NOTE 9 — POWER PURCHASE AGREEMENTS

The Company has two power purchase agreements ("Ormesa PPAs") with Southern California Edison ("SCE") related to the Ormesa Project. The Ormesa PPAs provide for the sale of capacity and energy through their respective terms, one expiring in 2017 and the other in 2018. Under the Ormesa PPAs, the Company receives a fixed energy payment through April 30, 2007, and thereafter an energy payment based on SCE's short-run avoided cost ("SRAC"). The Ormesa PPAs provide for firm capacity and bonus payments established by the contracts and are paid to the Company each month through the contracts' term based on plant performance. Bonus capacity payments are earned based on actual capacity available during certain peak hours.

In connection with the Ormesa PPAs, SCE has expressed its intent not to pay the contract rate for the power supplied by the GEM 2 and GEM 3 plants to the Ormesa project for auxiliary purposes. The Company has commenced discussions with SCE to resolve the dispute. In the interim period, SCE has tentatively agreed to pay a lower fixed price for such power. The Company cannot evaluate the potential long-term financial impact of a failure to reach a resolution with SCE, among other things because the current contract rates will fluctuate as of May 2007; however financial loss at the reduced price paid by SCE for the year ending December 31, 2005 may be in the range of $1 million. The Company is currently negotiating with a third party the sale of additional 10 MW under a long-term PPA.

The Company also has a power purchase agreement ("Brady PPA") with Sierra Pacific Power Company ("SPPC") related to the Brady power plants. The Brady PPA provides for the sale of energy and capacity over a term that expires in 2022. Energy payments under the Brady PPA are based on deliveries during specified winter and summer seasons for on-peak, mid-peak, and off-peak times.

The Company also has power purchase agreements ("Steamboat PPAs") with SPPC; two related to Steamboat 1 and 1A for the sale of energy and capacity that expire in 2006 and 2018, respectively, and two PPAs related to Steamboat 2 and 3 Power Plants that expire in 2022. Energy payments under

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the Steamboat 1 and 1A PPAs are based on the monthly average of the California-Oregon Border power market pricing, which is SPPC's adopted SRAC.

Pursuant to the terms of certain of the power purchase agreements, the Company may be required to make payments to the relevant power purchaser under certain conditions, such as shortfall on delivery of renewable energy and energy credits, and not meeting certain threshold performance requirements, as defined. The amount of payment required is dependent upon the level of shortfall on delivery or performance requirements and is recorded in the period the shortfall occurs. The Brady and Steamboat 2 and 3 PPAs provide that if the project does not maintain peak period capacity values of at least 85% of those listed in each of their respective contracts, the Company will be obligated to pay liquidated damages to SPPC in amounts ranging from $1.0 million to $1.5 million. If the Ormesa project fails to meet minimum performance requirements, as defined, such project may be placed on probation, the capacity of the relevant plant may be permanently reduced and, in such an instance, a refund would be owed from such project to SCE. Each of the projects may also reduce the capacity of the plants upon notice to SCE and after making a certain payment to it.

As required by EITF 01-8 (see Note 1), the Company assessed the PPAs acquired in connection with the acquisition of Steamboat 2 and 3 Projects (see Note 2), and concluded that all such PPAs contained a lease element requiring lease accounting. Accordingly, revenue related to the lease element of the PPA is presented as "lease portion of energy and capacity" revenue, with the remaining revenue related to the production and delivery of the energy being presented as "energy and capacity" revenue in the consolidated statements of operations. Future minimum lease revenues under PPAs which contain a lease element as of December 31, 2004 for Steamboat 2 and 3 were as follows:


For the year ending:	(dollars in thousands)
2005	$	10,917
2006		11,071
2007		11,230
2008		10,219
2009		10,295
Thereafter		133,989
Total	$	187,721

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 10 — INCOME TAXES

The components of income tax expense are as follows:


	Year Ended December 31,
	2004		2003		2002
	(dollars in thousands)
Current:
Federal	$	—	$	—	$	—
State		—		—		112
		—		—		112
Deferred:
Federal		64		1,542		2,183
State		10		590		439
		74		2,132		2,622
	$	74	$	2,132	$	2,734

The significant components of the deferred income tax expense are as follows:


	Year Ended December 31,
	2004			2003			2002
	(dollars in thousands)
Deferred tax expense (exclusive of the effect of other components listed below)	$	5,070		$	3,576		$	3,050
Expense (benefit) of operating loss carryforwards		(4,996	)		(150	)		249
Benefit of investment tax credits		—			(1,294	)		(677	)
	$	74		$	2,132		$	2,622

The differences between the U.S. federal statutory tax rate and the Company's effective rate are as follows:


	Year ended December 31,
	2004			2003			2002
U.S. Federal statutory tax rate		34.0	%		34.0	%		34.0	%
State income tax, net of federal benefit		2.3			4.0			3.7
Investment tax credits		—			(15.5	)		(7.8	)
Permanent differences and other		(10.5	)		3.0			1.8
		25.8	%		25.5	%		31.7	%

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The net deferred tax assets and liabilities consist of the following:


	December 31,
	2004			2003
Deferred tax assets (liabilities):
Depreciation	$	(14,977	)	$	(8,631	)
Asset retirement obligation		1,581			1,161
Net operating loss carryforwards		5,373			378
Investment tax credits		1,971			1,971
State income taxes		0			38
Total	$	(6,052	)	$	(5,083	)

Realization of the deferred tax assets and investment tax credits is dependent on generating sufficient taxable income prior to expiration of the loss carryforwards. Although realization is not assured, management believes it is more likely than not that the deferred tax asset will be realized.

At December 31, 2004 and 2003, the Company had federal net operating loss ("NOL") carryforwards of $13,894,000 and $1,071,000, respectively, and state NOL carryforwards of $15,039,000 and $313,000, respectively, available to reduce future taxable income, which expire between 2021 and 2024 for federal NOLs and between 2023 and 2024 for state NOLs. The investment tax credits in the amount of $2.0 million at December 31, 2004 carry over indefinitely until utilized.

NOTE 11 — TRANSACTIONS WITH RELATED ENTITIES

Effective January 1, 2002, April 15, 2002 and December 8, 2003, the Company entered into O&M Agreements with the Parent for the operations of the Brady Project, the Ormesa Project, and the Steamboat Projects, respectively. Under the O&M Agreements, the Company pays for: (i) fixed monthly fees in exchange for the Parent to operate and maintain the Brady, the Ormesa, and the Steamboat projects, including personnel, ordinary maintenance and general operating costs, (ii) extraordinary operation expenses such as capital expenditures and major maintenance, as defined in the agreement, that are not included in the fixed monthly fees, and (iii) plant and field maintenance, as defined in the agreement.

Amounts incurred by the Company under the O&M agreements with the Parent were $28,669,000, $24,630,000 and $15,751,000 for the years ended December 31, 2004, 2003 and 2002, respectively.

During the fourth quarter of 2002, the Parent transferred the Desert Peak assets to the Company, consisting of a small power plant that sells electricity to SPPC under the Brady PPA, at book value of $2.5 million.

On February 11, 2004, the Company, through ORNI 7, a wholly owned subsidiary of the Company, entered into a geothermal resource lease (the "Meyberg Lease") with ORNI 6, a wholly owned subsidiary of the Parent, granting ORNI 7 the right to extract geothermal steam from certain land identified in the lease. The lease also grants to ORNI 7 the right to construct and use wells, pumps, pipelines, brine pits, pumping stations and roads for the production and injection of geothermal resources. The Meyberg Lease has a primary term of five years. In February 2004, ORNI 7 paid to ORNI 6 $2.5 million for rent in the first year of the Meyberg Lease, which rent is being amortized on a straight-line basis over the five-year term of the lease. Additionally, after the first year, until such time as ORNI 7 commences production of geothermal resources in commercial quantities on the leased land, or if commercial production ceases after commencement of such production, ORNI 7 is required to pay ORNI 6 annual rent in the amount of $80,000. After commencing

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

commercial production, ORNI 7 will be required to pay monthly royalties to ORNI 6 in the amount of 5% of gross sales of electricity from any power plant that utilizes geothermal resources produced from the leased land.

Effective June 29, 2004, ORNI 7 signed a power purchase agreement, with respect to the Galena project ("Galena PPA"), with SPPC. The term of the Galena PPA is 20 years following the completion of the project, which completion is currently scheduled for the end of 2005. On August 2, 2004, the Company and the Parent entered into an engineering, procurement and construction agreement pursuant to which the Parent will design, engineer, and construct the Galena project and the Company will pay the Parent a total of $27.8 million, to be paid in installments, as compensation for its services.

Brady has a Fluid Supply Agreement with Western States pursuant to which Western States agrees to provide sufficient geothermal fluid from two wells to the Desert Peak 1 plant to allow Brady to generate up to 7 MW from the Desert Peak 1 plant. The fee for the geothermal fluid is 1% of the net revenues of Brady under the power purchase agreement to the extent that such revenues derive from the Desert Peak 2 plant and reimbursement of all rents and royalties paid by Western States to third parties under the geothermal lease, rights of way and other third party related property lease arrangements.

On August 2, 2004, ORNI 7 entered into engineering, procurement and construction agreement with the parent pursuant to which the Parent agreed to engineer and construct the Galena project on a turnkey basis. The cost under this engineering, procurement and construction agreement is $27.8 million subject to certain exceptions for change orders and changed circumstances such as force majeure and changes in law.

The U.S. Parent provides the Company with various accounting, legal, financial, developmental, operational, management and other services and assistance of the type customarily furnished by a parent corporation to its consolidated subsidiaries. The U.S Parent, is reimbursed indirectly by us, through payments to the Parent under the O&M agreements described above, for costs and expenses incurred by us and our subsidiaries in connection with provision of such services.

NOTE 12 — COMMITMENTS AND CONTINGENCIES

Geothermal resources

The Company, through its project subsidiaries, controls certain rights to geothermal fluids through certain leases with the Bureau of Land Management ("BLM") or through private leases. Royalties on the utilization of the geothermal resources are computed and paid to the lessors as defined in the respective agreements. Royalties expense was $1,342,000 $736,000 and $493,000 under the geothermal resource agreements for the years ended December 31, 2004, 2003 and 2002, respectively.

LOC Agreement

On June 30, 2004, the Parent entered into a letter of credit and loan agreement ("LOC Agreement") with a bank pursuant to which the bank agreed to issue one or more letters of credit aggregating to $15 million. The LOC Agreement expires on June 30, 2007, which shall be extended for successive one-year periods unless notice is provided by either the Parent or the bank to the contrary. In the event that the bank is required to pay on a letter of credit drawn by the beneficiary thereof, such letter of credit converts to a loan, bearing interest at LIBOR plus 4.0%, to be repaid in equal installments at the end of each of the next four quarters. There are various restrictive covenants in the LOC Agreement, which include maintaining certain levels of tangible net worth, leverage ratio, and minimum coverage ratio. On July 1, 2004, a letter of credit amounting to $8,125,000 was issued under the LOC Agreement, which has been used to replace cash on deposit in reserve funds that were used as a pledge against the Notes. Such letter of credit was increased by $2,674,000 on December 30, 2004.

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Contingencies

In response to an order issued by a California State Court of Appeals, the California Public Utilities Commission ("CPUC"), has commenced an administrative proceeding before an Administrative Law Judge to address short run avoided cost ("SRAC") pricing for Qualifying Facilities for the period spanning from December 2000 to March 2001. The California Court of Appeals directed that the CPUC modify SRAC pricing on a retroactive basis to the extent that the CPUC determined that SRAC prices were not sufficiently "accurate" or "correct." On February 15, 2005, the CPUC issued a draft decision affirming that SRAC prices during the disputed period were corrected and compliant with the Public Utility Regulated Policies Act ("PURPA") requirements and that no retroactive adjustments are warranted. All parties will have the opportunity to comment on the draft and a final decision from the CPUC could be issued in late March or early April 2005. If the SRAC prices charged during the period in question were determined by the CPUC to not be "accurate" or "correct," retroactive price adjustments could be required for any of the Company's Qualifying Facilities in California whose payments are tied to SRAC pricing, including the Mammoth and Ormesa projects. Currently it is not possible to predict the final resolution of such proceeding; however, any retroactive price adjustment required to be made in relation to any of the Company's projects may require such projects to make refund payments or charge less for future sales, which could materially and adversely affect the business, the financial condition, future results and cash flows of the Company.

Steamboat Geothermal, LLC ("SG") is party to litigation related to a dispute over amounts owed to the plaintiffs under certain operating agreements. SG has initiated settlement discussions with the plaintiff and the Company believes that any outcome will not have a material impact on the Company's results of operations.

The Company is a defendant in various other legal suits in the ordinary course of business. It is the opinion of the Company's management that the expected outcome of these matters, individually or in the aggregate, will not have a material effect on the results of operations and financial condition of the Company.

Certain of the Company's projects are subject to contested Federal Energy Regulatory Commission ("FERC") rulings whereby an adverse outcome could result in a refund of a portion of previous revenues and/or a reduction in future revenues from those projects. The outcome of this matter cannot be predicted at this time.

NOTE 13 — REVENUES

Total revenues in accordance with the power purchase agreements (see Note 9) are comprised as follows:


	Year Ended December 31,
	2004		2003		2002
	(dollars in thousands)
Energy	$	39,391	$	29,297	$	20,122
Capacity		16,569		11,545		10,865
Capacity bonus		1,148		1,043		464
Other		519		—		—
Total	$	57,627	$	41,885	$	31,451

A portion of the above revenues have been classified as lease revenues in the consolidated statements of operations to comply with the provisions of EITF Issue No. 01-8 (see Notes 1 and 9).

ORMAT FUNDING CORP. AND SUBSIDIARIES
(a wholly owned subsidiary of Ormat Nevada, Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 14 — COST OF REVENUES

Total cost of revenues in accordance with the power purchase agreements (see Note 9) is comprised as follows:


	Year Ended December 31,
	2004		2003		2002
	(dollars in thousands)
Depreciation, amortization and accretion of asset retirement obligation	$	10,298	$	5,564	$	3,049
Operating expenses		27,643		24,823		19,077
Total	$	37,941	$	30,387	$	22,126

A portion of the above cost of revenues have been classified as lease cost of revenues in the consolidated statements of operations to comply with the provisions of EITF Issue No. 01-8 (see Notes 1 and 9).

NOTE 15 — QUARTERLY CONSOLIDATED FINANCIAL INFORMATION (UNAUDITED)


	Three Months Ended
	March 31, 2003		June 30, 2003		Sept. 30, 2003		Dec. 31, 2003		March 31, 2004		June 30, 2004			Sept. 30, 2004		Dec. 31, 2004
	(dollars in thousands)
Total revenues	$	8,968	$	9,624	$	12,843	$	10,450	$	12,310	$	14,578		$	16,318	$	14,421
Gross margin		2,472		1,717		5,712		1,597		4,536		3,544			7,292		4,314
Income (loss) before cumulative effect of change in accounting principle		1,307		784		4,022		267		998		(343	)		1,494		(476	)
Net income (loss)		1,102		784		4,022		267		998		(343	)		1,494		(476	)

OrMammoth Inc.

(a wholly owned subsidiary of Ormat Funding Corp.)

Report on Audits of Financial Statements
As of December 31, 2004 and 2003, and for the Year
ended December 31, 2004 and for the period from
November 20, 2003 (date of incorporation) to
December 31, 2003

The accompanying notes are an integral part of these financial statements.

REPORT OF INDEPENDENT AUDITORS

To the Board of Directors and Stockholder of
OrMammoth Inc.

In our opinion, the accompanying balance sheets and the related statements of operations, of stockholder's equity and of cash flows present fairly, in all material respects, the financial position of OrMammoth Inc. (a wholly owned subsidiary of Ormat Funding Corp.) at December 31, 2004 and 2003, and the results of its operations and its cash flows for the year ended December 31, 2004 and for period from November 20, 2003 (date of incorporation) to December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Sacramento, California
March 21, 2005

ORMAMMOTH INC.
(a wholly owned subsidiary of Ormat Funding Corp.)
BALANCE SHEETS


	December 31,
	2004		2003
Assets
Investment in and advances to Partnership	$	36,360,796	$	38,773,031
Total assets	$	36,360,796	$	38,773,031
Liabilities and Stockholder's Equity
Long-term subordinated loan from Parent	$	34,759,401	$	38,631,379
Total liabilities	$	34,759,401	$	38,631,379
Contingencies (Note 4)
Stockholder's equity:
Common stock, par value $1 per share; authorized 3,000 shares; issued and outstanding 500 shares		500		500
Retained earnings		1,600,895		141,152
Total stockholder's equity		1,601,395		141,652
Total liabilities and stockholder's equity	$	36,360,796	$	38,773,031

The accompanying notes are an integral part of these financial statements.

ORMAMMOTH INC.
(a wholly owned subsidiary of Ormat Funding Corp.)
STATEMENTS OF OPERATIONS


	Year Ended December 31, 2004		Period From November 20, 2003 (date of incorporation) to December 31, 2003
Equity in income of Investee	$	1,459,743	$	141,152
Net income	$	1,459,743	$	141,152

The accompanying notes are an integral part of these financial statements.

ORMAMMOTH INC.
(a wholly owned subsidiary of Ormat Funding Corp.)
STATEMENTS OF STOCKHOLDER'S EQUITY


	Common Stock
	Shares		Amount		Retained Earnings		Total
Balance, November 20, 2003 (date of incorporation)		—	$	—	$	—	$	—
Issuance of shares to Parent		500		500		—		500
Net income		—		—		141,152		141,152
Balance, December 31, 2003		500		500		141,152		141,652
Net income		—		—		1,459,743		1,459,743
Balance, December 31, 2004		500	$	500	$	1,600,895	$	1,601,395

The accompanying notes are an integral part of these financial statements.

ORMAMMOTH INC.
(a wholly owned subsidiary of Ormat Funding Corp.)
STATEMENTS OF CASH FLOWS


	Year Ended December 31, 2004			Period From November 20, 2003 (date of incorporation) to December 31, 2003
Cash flows from operating activities:
Net income	$	1,459,743		$	141,152
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in income of investee		(1,459,743	)		(141,152	)
Distributions from Partnership		2,140,044			—
Deferred income tax provision		(894,682	)		—
Net cash provided by operating activities		1,245,362			—
Cash flows from investing activities:
Distributions from Partnership		2,500,000			—
Repayment of advances to Investee		126,616			—
Net cash provided by investing activities		2,626,616			—
Cash flows from financing activities:
Repayment of long-term subordinated loan from Parent		(3,871,978	)		—
Net cash used in financing activities		(3,871,978	)		—
Net change in cash		—			—
Cash, beginning of period		—			—
Cash, end of period	$	—		$	—
Supplemental non-cash investing and financing activities:
Issuance of common stock to Parent and incurrence of long-term subordinated loan from Parent	$	—		$	500
Transfer of 50% interest in Mammoth from Parent and incurrence of long-term subordinated loan from Parent	$	—		$	38,631,879

The accompanying notes are an integral part of these financial statements.

ORMAMMOTH INC.
(a wholly owned subsidiary of Ormat Funding Corp)

NOTES TO FINANCIAL STATEMENTS

NOTE 1 — BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Business

The primary business of OrMammoth Inc (the "Company"), a wholly owned subsidiary of Ormat Funding Corp. (the "Parent"), is holding a 50% ownership interest in Mammoth-Pacific, L.P. ("Mammoth"), who's operations are comprised of three geothermal power plants ("Mammoth Project"), located near the city Mammoth, California. The Parent is a wholly owned subsidiary of Ormat Nevada, Inc. ("ONI"), which is a wholly owned subsidiary of Ormat Technologies, Inc. (the "U.S. Parent"), which in turn is a wholly owned subsidiary of Ormat Industries Ltd. (the "Ultimate Parent").

Basis of presentation

As further discussed in Note 2, on December 18, 2003, ONI acquired a 50% ownership interest in Mammoth. On January 30, 2004, ONI transferred such 50% ownership interest in Mammoth to the Company at net book value. Such transfer has been accounted for as entities under common control in a manner similar to a pooling of interests of entities, and has been reflected in these financial statements as having occurred as of December 18, 2003. Prior to the transfer of ownership interests in Mammoth, the Company was a dormant entity. The Company was incorporated in Delaware on November 20, 2003.

The Company accounts for its 50% ownership interest in Mammoth under the equity method, pursuant to which original investments are recorded at cost and adjusted by the Company's share of undistributed earnings or losses of Mammoth. The Company's earnings in investments accounted for under the equity method have been reflected as "Equity in income of Investee" on the Company's statements of operations. Additionally, the Company has advances to Mammoth, which are included in "Investment in and advances to Partnership". Such advances totaled approximately $568,000 and $695,000 at December 31, 2004 and 2003, respectively. The advances will be repaid monthly, subject to available operating cash flows over a 20-year period beginning January 1, 1996. During the year ended December 31, 2004, Mammoth repaid $126,616 of the advances.

Income taxes

The Company is included in the U.S. Parent's consolidated federal and state tax returns as an affiliated group. Income taxes are accounted for by the Company using the separate return method pursuant to Statement of Financial Accounting Standards ("SFAS") No. 109, Accounting for Income Taxes. Under SFAS No. 109, the Company uses the asset and liability approach, which requires the recognition of taxes payable or refundable for the current year and deferred tax assets and liabilities for the future tax consequences of events that have been recognized in the Company's financial statements or tax returns. The measurement of current and deferred tax assets and liabilities are based on provisions of the enacted tax law; the effects of future changes in tax laws or rates are not anticipated. The Company accounts for investment tax credits as a reduction to income taxes in the year in which the credit arises. The measurement of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that, based on available evidence, are not expected to be realized. The current income taxes payable/receivable are recorded in amounts due to/from Parent as the Company settles such obligations currently.

Accounting estimates

ORMAMMOTH INC.
(a wholly owned subsidiary of Ormat Funding Corp)

NOTES TO FINANCIAL STATEMENTS

statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

New accounting pronouncements

FIN No. 46R — Consolidation of Variable Interest Entities

In January 2003, the Financial Accounting Standards Board issued Interpretation No. 46, Consolidation of Variable Interest Entities, which was revised in December 2003 ("FIN No. 46R"). FIN No. 46R clarifies the application of Accounting Research Bulletin No. 51, Consolidated Financial Statements, and applies immediately to any variable interest entities ("VIE's") created after December 31, 2003, and to variable interest entities in which an interest is obtained after that date. Effective March 31, 2004, the Company adopted the provisions of FIN No. 46R, which did not have an impact on its consolidated results of operations and financial position. The Company's equity investment in Mammoth does not require consolidation as Mammoth is not a VIE.

EITF Issue No. 02-14 — Whether an Investor Should Apply the Equity Method of Accounting to Investments Other Than Common Stock

In July 2004, the FASB issued EITF Issue No. 02-14, Whether an Investor Should Apply the Equity Method of Accounting to Investments Other Than Common Stock. EITF Issue No. 02-14 addresses whether the equity method of accounting applies when an investor does not have an investment in voting common stock of an investee but exercises significant influence through other means. EITF Issue No. 02-14 states that an investor should only apply the equity method of accounting when it has investments in either common stock or in-substance common stock of the investee, provided that the investor has the ability to exercise significant influence over the operating and financial policies of the investee. The provisions in EITF Issue No. 02-14 are effective for reporting periods beginning after September 15, 2004 (October 1, 2004 for the Company). The adoption of EITF Issue No. 02-14 by the Company did not have any impact on its results of operations and financial position.

NOTE 2 — BUSINESS ACQUISITIONS

The Mammoth Project

On December 18, 2003, ONI acquired a 50% interest in Mammoth for an allocated purchase price of $38.6 million. On January 31, 2004, ONI transferred such 50% interest in Mammoth to the Company at net book value, which approximated $38.8 million. The purchase price paid by the Parent was less than the underlying net equity of Mammoth by approximately $9.3 million. As such, the basis difference will be amortized over the remaining useful life of the property, plant and equipment and the power purchase agreements, which range from 12 to 17 years. The Company's 50% ownership interest in Mammoth is accounted for under the equity method of accounting as the Company has the ability to exercise significant influence, but not control, over Mammoth.

ORMAMMOTH INC.
(a wholly owned subsidiary of Ormat Funding Corp)

NOTES TO FINANCIAL STATEMENTS

The condensed financial position and results of operations of Mammoth are summarized below (amounts in thousands):


	December 31,
	2004		2003
Condensed balance sheet:
Current assets	$	11,088	$	11,182
Non-current assets		83,944		88,918
Current liabilities		924		608
Non-current liabilities		3,774		3,680
Partners' equity		90,334		95,812

(State or other jurisdiction of
incorporation or organization)

(I.R.S. Employer
Identification Number)

Ormat Funding Corp. 10-K