As filed with the Securities and Exchange Commission on February 10, 2012

Registration No. 333-173686

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

AMENDMENT NO. 6

FORM S-1

REGISTRATION STATEMENT

Under

The Securities Act of 1933

BrightSource Energy, Inc.

(Exact name of registrant as specified in its charter)

Delaware

4911

76-0836010

(State or other jurisdiction of incorporation or organization)

(Primary Standard Industrial Classification Code Number)

(I.R.S. Employer

Identification Number)

1999 Harrison Street, Suite 2150

Oakland, CA 94612

(510) 550-8161

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

John M. Woolard

President and Chief Executive Officer

BrightSource Energy, Inc.

1999 Harrison Street, Suite 2150

Oakland, CA 94612

(510) 550-8161

(Name, address including zip code, and telephone number including area code, of agent for service)

Copies to:

Alan Talkington

Brett Cooper

Orrick, Herrington & Sutcliffe LLP

405 Howard Street

San Francisco, CA 94105

Richard B. Aftanas

Skadden, Arps, Slate, Meagher & Flom LLP

Four Times Square

New York, NY 10036

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. ¨

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer ¨				Accelerated filer ¨
Non-accelerated filer þ (Do not check if a smaller reporting company)				Smaller reporting company ¨

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until this registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to Completion. Dated February 10, 2012.

PROSPECTUS

Shares

LOGO

Common Stock

This is an initial public offering of shares of common stock of BrightSource Energy, Inc. We are offering all of the shares of common stock to be sold in this offering.

Prior to this offering, there has been no public market for the common stock. It is currently estimated that the initial public offering price per share will be between $ and $ . We have applied to have the common stock listed on The Nasdaq Global Select Market under the symbol “BRSE.”

See “Risk Factors” on page 13 to read about factors you should consider before buying shares of the common stock.

Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.


	Per Share	Total
Initial public offering price	$	$
Underwriting discount	$	$
Proceeds, before expenses, to BrightSource	$	$

To the extent that the underwriters sell more than shares of common stock, the underwriters have the option to purchase up to an additional shares from us at the initial public offering price less the underwriting discount.

The underwriters expect to deliver the shares against payment in New York, New York on 2012.


Goldman, Sachs & Co.	Citi	Deutsche Bank Securities

Barclays Capital		Lazard Capital Markets

Baird		Raymond James

Prospectus dated , 2012.

LOGO

TABLE OF CONTENTS


	Page
Prospectus Summary		1
Risk Factors		13
Special Note Regarding Forward-Looking Statements		34
Use of Proceeds		35
Dividend Policy		35
Capitalization		36
Dilution		39
Selected Consolidated Financial Data		41
Management’s Discussion and Analysis of Financial Condition and Results of Operations		43
Market and Industry Data		75
Business		76
Management		98
Executive Compensation		108
Certain Relationships and Related Transactions		135
Principal Stockholders		140
Description of Capital Stock		143
Shares Eligible for Future Sale		147
Certain U.S. Federal Income Tax and Estate Tax Consequences to Non-U.S. Holders		149
Underwriting		153
Legal Matters		157
Experts		157
Where You Can Find More Information		158
Index to Consolidated Financial Statements		F-1

You should rely only on the information contained in this prospectus or contained in any free writing prospectus we file with the Securities and Exchange Commission, or the SEC. Neither we nor the underwriters have authorized anyone to provide you with additional information or information different from that contained in this prospectus or in any free writing prospectus filed with the Securities and Exchange Commission. We are offering to sell, and seeking offers to buy, our common stock only in jurisdictions where offers and sales are permitted. The information contained in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or of any sale of our common stock.

This prospectus contains forward-looking statements. The outcome of the events described in these forward-looking statements is subject to risks and actual results could differ materially. The sections entitled “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business,” as well as those discussed elsewhere in this prospectus, contain a discussion of some of the factors that could contribute to those differences.

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus and does not contain all of the information that you should consider in making your investment decision. Before investing in our common stock, you should carefully read this entire prospectus, including our consolidated financial statements and the related notes included elsewhere in this prospectus and the information set forth under the headings “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Unless the context requires otherwise, the words “BrightSource,” “we,” the “Company,” “us” and “our” refer to BrightSource Energy, Inc. and its subsidiaries.

Overview

BrightSource is a leading solar thermal technology company that designs, develops and sells proprietary systems that produce reliable, clean energy in utility-scale electric power plants. Our systems use proprietary solar power tower technology to deliver cost-competitive, renewable electricity with characteristics highly valued by utilities, such as reliability and consistency. Our systems are also used by industrial companies to create high-temperature steam for use in applications such as thermal enhanced oil recovery, or EOR.

Our systems use fields of tracking mirrors, known as heliostats, controlled by our proprietary software to concentrate sunlight onto a solar receiver/boiler unit to produce high-temperature steam. Once produced, the steam is used either in a conventional steam turbine to produce electricity or in industrial process applications such as thermal EOR. By integrating conventional power block components, such as turbines, with our proprietary technology and state-of-the-art solar field design, electric power plants using our systems can deliver cost-competitive, reliable and clean power when needed most. In addition, by incorporating thermal energy storage and/or integrating our technology with natural gas or other fossil fuels through a process referred to as hybridization, electric power plants using our systems can further increase output and reliability.

In implementing systems using our proprietary technology, we partner with several parties to develop utility-scale solar electric power plants. These parties include engineering, procurement and construction (EPC) contractors; boiler suppliers; turbine suppliers; and financing parties that may consist of strategic and/or financial investors. For instance, at Ivanpah Solar Electric Generating System, or Ivanpah, a 377 megawatt, or MW, project that commenced construction in October 2010, Bechtel is the EPC contractor, Riley Power is the boiler supplier, Siemens is the turbine supplier, and NRG Solar (a subsidiary of NRG Energy) and Google are together the controlling equity investors.

We have produced high-temperature steam using our technology since 2008, when we commenced operations at our 6 megawatt thermal, or MWth, demonstration solar-to-steam facility, the Solar Energy Development Center, in Israel. We believe this facility has consistently produced the highest temperature and pressure steam of any solar thermal facility in the world, capable of driving highly-efficient, cost-effective turbines. This facility validated our technology and continues to provide important operational and production data.

Through our project companies, we have 13 executed and outstanding long-term power purchase agreements, or PPAs, to deliver approximately 2.4 gigawatts, or GW, of installed capacity to two of the largest electric utilities in the United States, Pacific Gas and Electric Company, or PG&E, and Southern California Edison, or SCE. We believe these PPAs represent one of the largest utility-scale solar pipelines in the United States and should provide us with a significant revenue opportunity between 2013 and 2016. For purposes of illustration, our agreements for the supply of equipment and services to the Ivanpah project, which has three PPAs totaling 377 MW, represent $672.0 million of contracted sales, which equates to approximately $1.8 million of contracted sales per MW. Consistent with our 14% ownership in Ivanpah, we will recognize 86% of any actual sales as revenue.

As the first step in fulfilling our obligations under the PPAs, in 2007 we commenced the permitting and financing of Ivanpah, a project comprised of three concentrating solar thermal power plants on an approximately 3,500 acre site in California’s Mojave Desert. After receiving our permits, we initiated construction of Ivanpah in October 2010. In April 2011, Ivanpah was partially financed with a $1.6 billion loan guaranteed by the U.S. Department of Energy, or the DOE. Consistent with our business development strategy in the United States, we also transferred a controlling interest in the equity of Ivanpah to a consortium of investors led by NRG Solar. When commissioned, Ivanpah will have an installed capacity of 377 MW and will increase the amount of solar thermal generation capacity currently installed in the United States by over 75%.

We have a development site portfolio of approximately 90,000 acres under our control in California and the U.S. Southwest that has the potential to accommodate approximately 9 GW (gross) of installed capacity. We currently have three sites in advanced development, Rio Mesa Solar and Hidden Hills Ranch, each located in California, and Sandy Valley, located in Nevada. Rio Mesa Solar consists of approximately 5,800 acres, Hidden Hills Ranch consists of approximately 3,300 acres, and Sandy Valley consists of approximately 10,000 acres. In August 2011, we filed an Application for Certification with the California Energy Commission for the development of two 250 MW solar power plants at Hidden Hills Ranch. In October 2011, we filed an Application for Certification with the California Energy Commission for the development of three 250 MW solar power plants at Rio Mesa Solar.

In 2007, we entered the thermal EOR business after Chevron selected our technology through a competitive process. After winning the business, we signed a contract with Chevron in 2008 to provide a 29 MWth EOR facility in Coalinga, California. We commenced construction of the Coalinga Solar-to-Steam for EOR project in 2009, and the project began operations in October 2011.

In addition to our relationship with Chevron, we have strategic relationships with global, industry-leading companies, including Alstom, Bechtel, NRG Solar and Sasol. In order to accelerate the adoption of our systems, we are leveraging these relationships and our world-class partners’ local expertise in domestic and international markets to pursue expansion opportunities more rapidly and cost-effectively than might otherwise be possible.

Our Opportunities

For Utility Applications

According to a report released in 2010 by the Energy Information Administration (EIA), global demand for electric power is expected to increase 87% from 2007 to 2035 reaching 35.2 trillion kilowatt hours. Although fossil fuels such as coal, oil and natural gas generated approximately 68% of the world’s electricity in 2007, demand for alternative sources of electricity has grown significantly and is expected to continue to increase as a result of regulatory policies and incentives put in place to reduce carbon dioxide emissions and improve energy security. These policies and incentives are intended to stimulate deployment of renewable technologies and require utilities and grid operators to procure an increasing proportion of their energy supply from renewable sources. For instance, California has

recently adopted legislation requiring all California retail energy sellers, including municipal power agencies, to derive 33% of the energy they supply from renewable energy sources by 2020. In addition, recent global events have called into question future energy production from nuclear facilities, which the EIA in 2010 estimated will represent 12.8% of the global electricity generation in 2035. To the extent that production is cancelled or delayed, renewable energy sources will likely be called upon to help bridge the gap.

The production characteristics of some renewable energy sources present a number of integration challenges for utilities and grid operators. To ensure reliable and consistent electricity supply, utilities and grid operators (operators of electric transmission and distribution infrastructure) require the following:

Sufficient generation capacity available to meet peak demand: Peak demand represents the highest point of electricity consumption during any given period. Failure to meet peak demand, even for short periods of time can, at its worst, result in rolling blackouts and power outages.

The amount of power from renewable sources, especially wind and photovoltaic, or PV, has grown significantly in recent years. Although wind and PV power plants may provide clean energy with low variable costs compared to fossil fuel alternatives, their production characteristics, such as intermittency and lower peak availability, present a number of integration and reliability challenges for utilities and grid operators. These production characteristics add system integration costs. These system integration costs, combined with generation and transmission expenses, comprise the total system cost to the utility. This combination of system costs has been rising as more energy is produced from wind and PV resources and, as a result, is an increasingly important issue that utilities and regulators consider when evaluating new renewable energy capacity.

For Thermal EOR Applications

In addition to generating electricity, our systems can also be used for the production of steam for industrial process applications such as thermal EOR. Our technology enables steam flooding for thermal EOR, which is a proven, effective method of increasing production from heavy oil reserves. EOR is important to the future of oil production because conventional oil recovery methods are only able to extract about 10% to 30% of the original oil from a reservoir. With much of the easy-to-produce oil already recovered from developed oilfields, producers have attempted several techniques that offer prospects for ultimately recovering 30% to 60%, or more, of the reservoir’s original oil in-place. These techniques are generally referred to as EOR. According to BCC Research, the global market for EOR technologies was $4.7 billion in 2009 and is expected to grow at a 5-year compound annual growth rate of 28% to $16.3 billion in 2014.

Our Technology Solution

For Utility Applications

Our proprietary solar thermal technology is engineered to produce predictable, reliable and clean energy at a competitive cost. Our solution is specifically designed to address the challenges of utility-scale renewable power generation. Electric power plants using our systems provide:

Sufficient generation capacity at peak demand: Our power production profile, or the amount of power electric power plants using our systems produce at different times of the day,

can be tailored to the demand profile that most utilities serve. This significantly enhances the average revenue per megawatt hour, or MWh, that our system is able to generate compared to other renewable sources which typically produce power well below their capacity during peak demand periods.

Increased production capability through thermal energy storage and hybridization: In contrast to wind and PV, our technology allows the incorporation of existing cost-effective thermal energy storage and hybridization. These features can extend the hours of our production, reduce system integration costs and increase the reliability and consistency of our systems. Specifically, thermal energy storage reduces the cost of electricity by increasing a plant’s capacity factor, and, according to the National Renewable Energy Laboratory, or NREL, allows electricity generation to be shifted to critical hours with higher energy prices and enables more thermal energy to be utilized from the solar field. As utilities purchase greater amounts of electricity from renewable energy sources, we believe energy storage and hybridization with other sources such as natural gas will make electric power plants using our systems increasingly valuable to utilities and grid operators.

As a result of the characteristics discussed above, electric power plants using our systems deliver electricity with characteristics highly valued by utilities, such as reliability and flexibility, at a competitive total system cost. While electric power plants using our systems are not yet as reliable as dispatchable fossil fuel plants, they are more reliable and have lower integration costs than highly intermittent renewable technologies such as wind and PV. In addition, by providing energy during peak demand when utilities are willing to pay the highest price, electric power plants using our systems are able to maximize the revenue realized from the sale of electricity. Moreover, as the power grid is loaded with increasing quantities of renewable energy, we believe that we will have a competitive advantage over other renewable technologies that have higher total system costs and do not produce electricity as reliably during periods of peak demand.

For Thermal EOR

Our solar-to-steam solution for thermal EOR is designed to offer oil production and industrial companies a clean, emission-free alternative with the best combination of efficiency, ease of permitting and implementation. Our high-temperature steam is easily integrated into steam produced from other sources at the oilfield, allowing efficient use of existing infrastructure and integration into operations.

Our Strengths

We believe that the following competitive strengths position us as a leader within the utility-scale renewable energy market:

Superior technology: Our system can deliver clean, reliable power that naturally extends late in the day, and can be complemented with thermal energy storage and hybridization to address peak electricity demands at a competitive cost. The foundation of our technology is our solar field optimization software and proprietary control system that together optimize the output of energy from our system to match the needs of utilities and maximize project revenue.

Substantial revenue visibility with fully committed, long-term agreements: Through our project companies, we have 13 executed and outstanding PPAs with two of the largest electric utilities in the United States, PG&E and SCE, to deliver approximately 2.4 GW of installed capacity. Three of the PPAs are associated with Ivanpah, and we have transferred a controlling interest to a third party. We retain 10 PPAs to deliver approximately 2.0 GW of installed capacity. To the extent we can finance and successfully build the capacity to deliver on those contracts, we believe these PPAs should provide us with a significant revenue opportunity through sales of our systems to the project companies or EPC contractors. Our agreements for the supply of equipment and services to the Ivanpah project, which has three PPAs totaling 377 MW, represent $672.0 million of contracted sales, which equates to approximately $1.8 million of contracted sales per MW. Consistent with our 14% ownership in Ivanpah, we will recognize 86% of any actual sales as revenue.

Experienced management team: Our team has extensive solar thermal technical and project development expertise and has collectively developed, constructed and managed more than 25 GW of solar and conventional power projects worldwide. The principal members of our technical team designed and developed solar thermal power plants representing approximately 70% of the solar thermal generation capacity currently installed in the United States.

Demonstrated alternative applications of our solar thermal technology: We use our technology to provide the oil and gas industry with a clean, emission-free alternative to traditional fossil fuel-based steam generation methods for thermal EOR, which is particularly attractive in remote areas with limited infrastructure or high fuel costs. EOR and other industrial process applications of our technology diversify our revenue streams and contribute to our future growth.

Strong global partners support our expansion: We believe our partnerships with leading, global companies such as Alstom, Chevron, NRG Solar and Bechtel provide a strong competitive advantage. By leveraging these relationships and our world-class partners’ local expertise in domestic and international markets, we believe we can enter new markets and pursue expansion opportunities more rapidly and cost-effectively than might otherwise be possible.

High-quality development site portfolio: To accelerate the development of our technology and satisfy our signed PPAs, we are developing projects in the United States. We have a development site portfolio of approximately 90,000 acres under our control in California and the U.S. Southwest that is well suited for solar power generation. This portfolio has the potential to accommodate approximately 9 GW (gross) of installed capacity.

Low impact design: Our systems are designed to have a low impact on the site, limiting changes to topography, soil conditions and vegetation. They also cost-effectively use air instead of water to cool steam, which reduces water usage by more than 90% over competing solar thermal technologies that use conventional wet-cooling systems.

Our Growth Strategies

We intend to pursue the following growth strategies to maintain and expand our position as a leader within the utility-scale renewable energy market:

Leverage our PPAs into sales of systems using our technology: We intend to use our high-quality development site portfolio to create attractive opportunities for projects where we can sell our solar thermal technology. To the extent we can finance and successfully build the capacity to deliver on those contracts, we expect to generate substantial revenue, cash flow and profit growth, providing us with the ability to scale and the resources needed to pursue broader growth opportunities.

Focus on identifying and creating additional opportunities to sell our systems: We focus our business development efforts on identifying new projects and additional PPAs in domestic markets and work with strategic partners in international target markets that are characterized by high levels of direct sunlight and energy demand. In addition, we expect to leverage the performance of the Coalinga Solar-to-Steam for EOR project to establish additional relationships for thermal EOR and other solar-to-steam applications.

Develop additional relationships with global industry leaders: We intend to create new relationships with global industry leaders to expand our business. We intend to leverage these new and existing relationships to enter additional markets and pursue expansion opportunities more rapidly and cost-effectively. For example, in February 2012, we and Alstom entered into an agreement with Sasol to conduct a comprehensive front-end engineering and design study for the South Africa market.

Continue to improve our proprietary solar thermal technology: While our systems are currently cost-competitive, we expect our technology roadmap to yield significant cost reductions and a lower total system cost to utilities. We intend to continue to lead innovation in solar thermal technology and drive greater capital and operating efficiencies with each new generation of solar power tower technology.

Enhance operating characteristics utilities value most: We recently introduced solar thermal energy storage capabilities and intend to pursue additional system enhancements such as hybridization where appropriate. We expect these enhancements to yield a lower total system cost to utilities through greater on-peak availability, higher reliability and increased output.

Risks We Face

There are a number of risks and uncertainties that may affect our business, financial and operating performance and growth prospects. You should carefully consider all of the risks discussed in “Risk Factors,” which begin on page 13, the other information contained in this prospectus and our consolidated financial statements and the related notes before investing in our common stock. These risks include, among others:

We have generated substantial net losses and negative operating cash flows since our inception and expect to continue to do so for the foreseeable future as part of the development and construction of solar thermal energy projects using our systems;

Our proprietary technology has a limited history and may perform below expectations when implemented on utility-scale projects;

Our future growth is dependent upon the successful implementation of Ivanpah, the first utility-scale solar thermal power project using our technology, as well as the Coalinga Solar-to-Steam for EOR project;

We may be required to fund cost overruns over the funded reserves for the completion of Ivanpah;

We may not be able to finance the growth of our business, which we expect will require significant amounts of capital, including the development and construction of solar thermal energy projects using our systems;

We depend heavily on federal, state and local government support for renewable energy sources, which is subject to change;

Our industry is rapidly evolving and highly competitive and failure to further refine and develop improved technologies could render our solar thermal technology obsolete and reduce our sales and market share relative to other renewable energy sources;

Our ability to execute on our existing pipeline of PPAs and solar-to-steam contract, as well as our ability to sell our systems, depends in large part on locating suitable sites, securing site control and sufficient transmission capacity, and obtaining necessary governmental approvals and permits, the failure of which would adversely affect our business;

Current or future litigation or administrative proceedings could have a material adverse effect on our business, financial condition and results of operations; and

Problems with system component quality or performance at Ivanpah may cause us to incur solar field and receiver system warranty expenses and may damage our market reputation and cause our revenue to decline.

Corporate Information

BrightSource Energy, Inc. was formed as a Delaware limited liability company on April 5, 2004 and converted into a Delaware corporation on August 17, 2006. Our principal executive offices are located at 1999 Harrison Street, Suite 2150, Oakland, California 94612, and our telephone number at this location is (510) 550-8161. Our website address is www.brightsourceenergy.com. Information contained on our website is not a part of this prospectus and the inclusion of our website address in this prospectus is an inactive textual reference only. As of December 31, 2011, we had 410 employees worldwide.

The BrightSource and BrightSource Energy logos, and other trademarks, including SolarPLUS^™, or service marks of BrightSource appearing in this prospectus are the property of BrightSource. BrightSource^® is a registered trademark of BrightSource Energy, Inc. Trade names, trademarks and service marks of other companies appearing in this prospectus are the property of the respective holders.

The Offering


Common stock offered by us		shares (or shares if the underwriters exercise their option to purchase additional shares in full).

Shares outstanding after the offering		shares.

Use of proceeds		We estimate that we will receive net proceeds from this offering of approximately $ million ($ if the underwriters’ option to purchase additional shares is exercised in full) based on an assumed initial public offering price of $ per share (the midpoint of the price range set forth on the cover of this prospectus) and after deducting underwriting discounts and commissions and estimated offering expenses. We currently intend to use the net proceeds from this offering for working capital, capital expenditures and general corporate purposes, which may include domestic and international development activities, hiring additional personnel and investing in research and development.

Risk factors		See “Risk Factors” beginning on page 13 and the other information included elsewhere in this prospectus for a discussion of factors you should carefully consider before deciding to invest in our common stock.

Proposed Nasdaq Global Select Market symbol		BRSE

The number of shares of our common stock to be outstanding after this offering is based on 94,404,725 shares of our common stock outstanding as of December 31, 2011, after giving effect to the conversion of our outstanding Series A, B, C, D and E convertible preferred stock into 79,196,331 shares of common stock immediately prior to the completion of this offering. The number of shares of our common stock actually issued upon the conversion of our outstanding shares of Series E preferred stock, which will occur immediately prior to the completion of this offering, depends in part on the actual initial offering price of our common stock in this offering. The terms of our Series E preferred stock provide that the ratio at which each share of Series E preferred stock automatically converts into shares of our common stock in connection with a qualified IPO (for which this offering will qualify) will increase if the initial offering price per share of common stock in the qualified IPO is below a specified minimum dollar amount, which would result in additional shares of common stock being issued upon conversion of the Series E preferred stock. In the event the actual initial public offering price is lower than $ per share, the shares of Series E preferred stock will convert into a larger number of shares of common stock; if the initial public offering price is equal to the midpoint of the range on the cover of this prospectus, the Series E preferred stock would convert into shares of common stock. A $1.00 decrease in the initial public offering price would increase by , and a $1.00 increase in the initial public offering price would decrease by , the number of shares of common

stock issuable upon conversion of the Series E preferred stock. The number of shares of our common stock to be outstanding after this offering excludes:

11,012,160 shares issuable upon the exercise of options outstanding as of December 31, 2011 at a weighted average exercise price of $3.72 per share under our 2006 Stock Plan;

325,772 shares issuable upon exercise of warrants outstanding as of December 31, 2011 at a weighted average exercise price of $7.89 per share;

3,995,168 shares reserved for issuance upon exercise of options that may be granted subsequent to December 31, 2011 under our 2006 Stock Plan;

12,000,000 shares of common stock (plus the shares reserved for issuance under our 2006 Stock Plan that are not issued or subject to outstanding grants at the completion of this offering) reserved for future issuance under our 2011 Omnibus Incentive Plan, which will become effective upon the completion of this offering and which will also contain provisions that will automatically increase its share reserve each year, as more fully described in “Executive Compensation—Stock Plans”; and

1,000,000 shares of common stock reserved for future issuance under our 2011 Employee Stock Purchase Plan, which will become effective upon the completion of this offering and will also contain provisions that will automatically increase its share reserve each year, as more fully described in “Executive Compensation—Stock Plans.”

Except as otherwise indicated, information in this prospectus reflects or assumes the following:

the automatic conversion of all of our outstanding preferred stock into an aggregate of 79,196,331 shares of common stock immediately prior to the completion of this offering (which does not give effect to any additional shares of common stock issuable upon conversion of the Series E preferred stock, as described above);

the exercise of warrants to purchase 60,387 shares of Series A preferred stock in December 2011; and

no exercise of the underwriters’ right to purchase up to an additional shares of our common stock.

Summary Consolidated Financial Information

The following summary consolidated financial and operating data set forth below should be read in conjunction with our consolidated financial statements, the notes thereto and the other information contained in this prospectus. The summary consolidated balance sheet data as of December 31, 2009 and 2010, and the summary consolidated statements of operations data for the years ended December 31, 2008, 2009 and 2010, have been derived from our audited consolidated financial statements appearing elsewhere in this prospectus. The summary consolidated statements of operations data for the nine months ended September 30, 2010, and 2011 and balance sheet data as of September 30, 2011 are derived from our consolidated financial statements that are included elsewhere in this prospectus. The unaudited consolidated financial statements were prepared on a basis consistent with our audited consolidated financial statements and include, in the opinion of management, all adjustments necessary for the fair presentation of the financial information contained on those statements. The historical results presented below are not necessarily indicative of financial results to be achieved in future periods.


	Year Ended December 31,									Nine Months Ended September 30,
	2008			2009			2010			2010			2011
	(in thousands, except share and per share data)
Consolidated Statements of Operations Data:
Revenues	$	7,082		$	11,573		$	13,494		$	11,468		$	71,203
Cost of revenues		17,214			19,014			31,457			22,456			80,762

Gross loss		(10,132	)		(7,441	)		(17,963	)		(10,988	)		(9,559	)
Operating expenses:
Research and development(1)		16,645			9,717			8,551			6,058			13,821
Project development(1)		8,397			12,392			18,226			12,267			19,597
Marketing, general and administrative(1)		10,619			14,331			24,367			16,918			28,922
Loss on deconsolidation of consolidated subsidiary		—			—			—			—			22,824

Loss from operations		(45,793	)		(43,881	)		(69,107	)		(46,231	)		(94,723	)
Interest income (expense), net		1,673			(150	)		(1,949	)		(365	)		(7,861	)
Other income (expense), net		(488	)		268			(553	)		(500	)		(1,021	)

Loss before income taxes		(44,608	)		(43,763	)		(71,609	)		(47,096	)		(103,605	)
Provision for income taxes		10			17			22			18			83

Net loss	$	(44,618	)	$	(43,780	)	$	(71,631	)	$	(47,114	)	$	(103,688	)

Net loss per share of common stock, basic and diluted(2)	$	(4.42	)	$	(4.03	)	$	(4.93	)				$	(6.86	)

Shares used in computing net loss per share of common stock, basic and diluted(3)		10,084,167			10,853,073			14,527,834						15,115,786

Pro forma net loss per share of common stock, basic and diluted(4)							$	(1.12	)				$	(1.15	)

Weighted average shares used in computing the pro forma net loss per share of common stock, basic and diluted								63,684,677						90,282,311

(1)	Includes share-based compensation expense as follows:


	Year Ended December 31,						Nine Months Ended September 30,
	2008		2009		2010		2010		2011
	(in thousands)
Research and development	$	120	$	218	$	264	$	193	$	577
Project development		273		374		675		465		863
Marketing, general and administrative		575		816		1,398		792		2,197

Total	$	968	$	1,408	$	2,337	$	1,450	$	3,637

(2)

Our basic net loss per share of common stock is calculated by dividing the net loss by the weighted average number of shares of common stock outstanding for the period. The diluted net loss per share of common stock is computed by dividing the net loss by the weighted average number of shares of common stock (excluding common stock subject to repurchase) and, if dilutive, potential shares of common stock outstanding during the period. Potential shares of common stock consist of stock options to purchase shares of our common stock and warrants to purchase shares of our convertible preferred stock (using the treasury stock method) and the conversion of our convertible preferred stock (using the if-converted method). For purposes of these calculations, potential shares of common stock have been excluded from the calculation of diluted net loss per share of common stock as their effect is antidilutive since we generated a net loss in each period.

(3)

The basic and diluted net loss per share computation excludes potential shares of common stock issuable upon conversion of convertible preferred stock and exercise of options and warrants to purchase common stock as their effect would be antidilutive. See note 18 to our consolidated financial statements for a detailed explanation of the determination of the shares used in computing basic and diluted loss per share.

(4)	Pro forma basic and diluted net loss per share of common stock has been computed to give effect to (i) the conversion of the convertible preferred stock into common stock and (ii) the exercise of warrants to purchase 60,387 shares of Series A preferred stock in December 2011.

Our consolidated balance sheet data as of September 30, 2011 is presented:

on an actual basis;

on a pro forma basis to reflect (i) the conversion of all of our shares of convertible preferred stock outstanding as of September 30, 2011, into 79,135,944 shares of common stock upon the completion of this offering (which does not give effect to any additional shares of common stock issuable upon conversion of the Series E preferred stock, as described in “—The Offering”); (ii) the exercise of warrants to purchase 60,387 shares of Series A preferred stock in December 2011; and (iii) the effectiveness of our amended and restated certificate of incorporation in Delaware immediately prior to the completion of this offering; and

on a pro forma as adjusted basis as of such date to give effect to the pro forma adjustments and receipt and application of the net proceeds from the sale by us of shares of common stock offered hereby at an assumed initial public offering price of $ per share (the midpoint of the price range set forth on the cover of this prospectus).


	As of September 30, 2011
	Actual		Pro forma		Pro forma as adjusted
	(in thousands)
Consolidated Balance Sheet Data:
Cash and cash equivalents	$	238,748	$	238,748	$
Property, plant and equipment, net		26,767		26,767
Capitalized project costs		23,544		23,544
Working capital		17,012		18,531
Total assets		608,678		608,678
Preferred stock warrant liability		2,574		2,574
Long-term liabilities, less current portion		30,667		29,612
Temporary equity		196,737		—
Total stockholders’ equity	$	59,078	$	255,815

RISK FACTORS

This offering involves a high degree of risk. You should carefully consider the risks and uncertainties described below and the other information in this prospectus before deciding whether to invest in shares of our common stock. If any of the following risks actually occur, our business, financial condition or operating results could be materially adversely affected. This could cause the trading price of our common stock to decline, and you may lose part or all of your investment.

This prospectus also contains certain forward-looking statements that involve risks and uncertainties. These statements refer to our future plans, objectives, expectations and intentions. These statements may be identified by the use of words such as “expects,” “anticipates,” “intends,” “plans” and similar expressions. Our actual results could differ materially from those discussed in these statements. Factors that could contribute to these differences include those discussed below and elsewhere in this prospectus.

Risks Relating to Our Business and Industry

We have generated substantial net losses and negative cash flows from operating activities since we commenced operations. We have incurred losses of approximately $281.0 million from our inception through September 30, 2011. For the year ended December 31, 2010 and nine months ended September 30, 2011, we incurred a net loss of $71.6 million and $103.7 million, respectively, and our net cash provided by (used in) operating activities was $(64.1) million and $74.5 million, respectively.

We expect that our net losses and our negative operating cash flows will continue for the foreseeable future, as we increase our development activities and construct solar thermal energy projects. Solar thermal energy projects typically accumulate negative cash flow during development prior to commercial operation at which point the projects generally are expected to begin to generate positive operating cash flow. Currently, our project development generally begins approximately three to seven years before commercial operation. We also expect to incur the incremental costs of operating as a public company, contributing to our losses and operating uses of cash. Our costs may also increase due to such factors as higher than anticipated financing and other costs; non-performance by third-party suppliers or subcontractors; increases in the costs of labor or materials; and major incidents or catastrophic events. If any of these or similar factors occur, our net losses and accumulated deficit could increase significantly and the value of our common stock could decline.

Our proprietary technology has a limited history and may perform below expectations when implemented on utility-scale projects.

We use proprietary technology that has not been previously implemented on utility-scale projects of the size and complexity of the Ivanpah Solar Electric Generating System, or Ivanpah, and Ivanpah may experience technological problems that neither we nor any of the third-party independent engineers that have reviewed our projects are able to foresee. The systems that we will implement on utility-scale projects include a solar field with heliostats controlled by advanced software systems that concentrate sunlight onto a receiver to produce high-temperature steam. If the implementation of our proprietary technology is unsuccessful, it could negatively impact the successful operation of projects using our systems and may result in additional payments, deductions or defaults under key project documents, including our PPAs or other financing arrangements.

Furthermore, given the size and complexity of Ivanpah and other utility-scale projects’ solar field construction and the fact that third-party contractors will be assembling systems using new and

unproven processes, there may be potential construction delays and unforeseen cost overruns. Delays at any single phase of construction may significantly impact the overall timing of commencing operations at Ivanpah.

In addition, there is a lack of long-term reliability data for our proprietary systems and technology. Actual long-term performance of these parts, including heliostats in the field, may fall short of expectations. Heliostats may be susceptible to damage from weather-related or other unforeseen events. Furthermore, our SolarPLUS solar thermal power plant solution, which combines our solar power tower technology with two-tank molten-salt storage capabilities, may not perform as expected. Equipment performance issues at our projects could result in significant operational problems for our company, including increased maintenance costs, decreased revenue, inability to meet energy delivery requirements or defaults under project or financing documents.

Our future success depends on the ability to construct Ivanpah, the first utility-scale solar thermal power project using our technology, in a cost-effective and timely manner. The ability to complete Ivanpah and the planning, development and construction of all three phases are subject to significant risk and uncertainty, including:

Ivanpah is being primarily financed by a U.S. Department of Energy, or DOE, guaranteed loan facility, which requires the project companies to remain in compliance with numerous financial, construction and operational covenants to draw funds under the loan facility, compliance with which are within the control of NRG Solar, the majority equity owner and operator of Ivanpah;

the construction of any of our projects will be subject to the risks inherent in the construction of solar thermal projects that have never been built on the scale of Ivanpah, including risks of delays and cost overruns as a result of a number of factors, many of which may be out of our control, such as delays in government approvals, burdensome permit conditions and delays in the delivery of materials and equipment that we manufacture or obtain from suppliers;

our customized system and equipment may take longer and cost more to engineer and build than expected and may never operate as required to meet our production plans, which production plans are guaranteed pursuant to our construction and supply contracts with Ivanpah;

we depend on third-party relationships to produce components in our system, which may subject us to risks that such third parties do not fulfill their obligations to us under our arrangements with them;

once implemented at utility-scale, our solar thermal technology may perform below expectations, which may implicate the production guarantees in our construction and supply contracts with Ivanpah; and

if Ivanpah fails to comply with its permits, including those relating to protection of the environment and natural resources, or if unexpected conditions are encountered during construction or operation that require that these permits be re-evaluated, Ivanpah may be required to halt or delay construction or operation.

Once construction is completed, Ivanpah will be operated by NRG Solar, and therefore we will have limited influence over Ivanpah’s future operations. If the construction and operation of Ivanpah are not successful, we may be unable to grow our business to a sufficient scale necessary to improve our results of operations and achieve profitability.

Furthermore, adoption of our systems for use in solar-to-steam applications, such as thermal EOR, depends on the successful implementation and operation of the 29 MWth EOR project for Chevron in Coalinga, California that began operations in October 2011. We have experienced significant cost overruns related to the project. If the Coalinga Solar-to-Steam for EOR project does not meet expectations, our ability to sell additional thermal EOR systems may be negatively impacted.

We may be required to fund cost overruns over the funded reserves for the completion of Ivanpah.

If Ivanpah’s costs exceed the budgeted amount, we, along with the other equity owners of Ivanpah, have committed to funding up to $66.5 million of overrun contingency reserves, known as the funded overrun equity. To the extent Ivanpah’s cost overruns exceed the funded overrun equity, we are responsible for all further cost overruns. Cost overruns may occur if completing the portion of Ivanpah construction that is within our scope of responsibility costs more than expected, or when one of Ivanpah’s contractors or suppliers encounter unexpected cost increases that entitle them to relief from their fixed-price contracts. If we are required to fund cost overruns over and above the funded overrun equity, we will not be entitled to recover this additional funding through future distributions from Ivanpah to the equity owners.

We are in a capital-intensive business and have relied heavily on debt and equity issuances and government grants and loan guarantees to finance the development and construction of our projects and other projected capital expenditures. For the projects where we lead development, we expect to own initially 100% of the equity in the projects, but may seek development partners on specific projects. We intend to ultimately transfer the majority of the equity in these projects to third parties while retaining a minority equity interest. Completion of our projects requires significant capital expenditures and construction costs. For example, in April 2011, we closed an approximately $2.2 billion financing for the construction of Ivanpah. Recovery of the capital investment in a solar thermal energy project generally occurs over a long period of time. As a result, we must obtain funds from equity or debt financings, including tax equity transactions, or from government grants to help develop and construct our existing project pipeline, to help finance the acquisition of system components, to help identify and develop new projects, to help fund research and development expenses and to help pay the general and administrative costs of operating our business. We may not be able to obtain the needed funds on terms acceptable to us, or at all. For example, Ivanpah was primarily financed by a $1.6 billion loan, guaranteed by the DOE and funded by the Federal Financing Bank, a branch of the U.S. Department of the Treasury, or the U.S. Treasury, but government funding may not be available to finance future projects. Furthermore, because we rely on debt financing to develop our projects, increases in long-term interest rates could significantly increase our cost of capital. If we are unable to raise additional funds when needed, our project companies could be required to delay development and construction of projects, reduce the scope of projects or abandon or sell some or all of their development projects or default on our contractual commitments in the future, any of which would adversely affect our business, financial condition and results of operations.

We depend heavily on federal, state and local government support for renewable energy sources, which is subject to change.

We depend heavily on government policies that support renewable energy and enhance the economic feasibility of developing solar energy projects. Renewable energy sources currently benefit from various federal, state and local governmental incentives such as investment tax credits, or ITCs,

cash grants in lieu of ITCs, loan guarantees, renewables portfolio standard programs, or RPS programs, modified accelerated cost-recovery system of depreciation and bonus depreciation. For example, the Internal Revenue Code of 1986, as amended, or the Code, provides an ITC of 30% of the cost-basis of an eligible resource, including solar thermal energy projects placed in service prior to the end of 2016. Additionally, many states have adopted RPS programs mandating that a specified percentage of electricity sales come from eligible sources of renewable energy. However, the regulations that govern the RPS programs, including pricing incentives for renewable energy, or reasonableness guidelines for pricing that increase valuation above conventional power (such as a projected value for carbon reduction), may change. If the RPS requirements are reduced or eliminated, we could sustain fewer future power contracts or receive lower prices for the sale of power in future power contracts, which could have a material adverse effect on us and our project development plans. Such material adverse effects may result from decreased revenues, reduced economic returns on certain project company investments, increased financing costs, and/or difficulty obtaining financing. Furthermore, the American Recovery and Reinvestment Act of 2009, or ARRA, included over $80 billion in incentives to encourage investment in the renewable energy sector, such as cash grants in lieu of ITCs, bonus depreciation and expansion of the DOE loan guarantee program. Although the ARRA expanded the DOE loan guarantee program, this program faces challenges and may not continue past the projects already financed such as Ivanpah. In addition, the cash grant in lieu of ITCs program only applies to projects that commence construction prior to December 31, 2011.

The renewable energy industry is highly competitive, and if we fail to identify and adapt to new technologies, such failure could have a material adverse effect on our business, financial condition and results of operations. In order to remain competitive, we will need to invest significant financial resources in research and development to keep pace with technological advances in the solar energy industry. However, returns on research and development activities are inherently uncertain, and we could encounter practical difficulties in commercializing our research results. Our significant expenditures on research and development may not produce corresponding benefits. Other companies are developing a variety of competing solar energy technologies, including crystalline silicon and thin film technologies, that could produce solar energy systems that may prove more cost-effective or more efficient than our technology. As a result, if we do not execute on our technology roadmap as planned, our solar thermal technology may be rendered obsolete by the technological advances of others, which could reduce our revenue and market share.

Our ability to execute on our existing pipeline of PPAs and solar-to-steam contract, as well as our ability to sell our systems, depends in large part on locating suitable sites, securing site control and obtaining and complying with necessary governmental approvals and permits, the failure of which would adversely affect our business.

Our ability to convert our PPAs and solar-to-steam contracts into sales of systems using our technology depends in large part on locating sites suitable for construction of a solar thermal energy project, securing site control and obtaining necessary governmental approvals and permits. Electric power plants using our systems must be interconnected to electricity transmission, gas transmission and distribution networks. For example, our PPAs require specific interconnection points for the transmission of electricity and if our project companies are unable to connect at such points, we may have to seek the counterparty’s approval, amend or renegotiate the PPA. Solar thermal energy projects using our systems must also secure an adequate water supply primarily for periodic washing of heliostats.

Once projects using our systems have identified a suitable operating site, obtaining the necessary land rights requires negotiation with landowners and local government officials, which can take a long

period of time, is not always successful and sometimes requires economic concessions not originally planned. The design, construction and operation of solar thermal energy projects are highly regulated, require various governmental approvals and permits, including environmental approvals and permits, and may be subject to the imposition of conditions that vary by jurisdiction. In some cases, these approvals and permits require periodic renewal. In addition, third-party permits may be required for transmission upgrades needed to deliver electricity from our projects, and such transmission is also highly regulated and requires various governmental approvals and permits, including environmental approvals and permits. We cannot predict whether all approvals and permits required for a given project will be granted or whether the conditions associated with the approvals and permits will be achievable or financially practicable. The denial of an approval or a permit essential to a project or the imposition of impractical conditions on a project would impair our ability to develop projects necessary to meet the commercial operation deadlines under our PPAs. In addition, we cannot predict whether the approvals and permits will attract significant opposition or whether the permitting process will be lengthened due to complexities of appeals or litigation by local, state or federal parties.

Our project companies have experienced delays in developing projects due to delays in obtaining permits and may experience delays in the future. This delay in the review and permitting process for a project can impair the ability to develop a project or increase the cost so substantially that the project is no longer attractive to us or the owners of projects using our systems. If we were to commence construction in anticipation of our project companies obtaining the final permits needed for a project, we would be subject to the risk of being unable to complete the project if all the permits were not obtained. If this were to occur, we would likely lose a significant portion of our investment in the project company and could incur a loss as a result. Any failure to procure and maintain necessary permits would adversely affect ongoing development, construction and operation of projects using our systems.

Furthermore, federal and state environmental legislation and regulations are subject to change, and future requirements may include stricter standards and enforcement, as well as more stringent fines and penalties for non-compliance. Environmental assessments of proposed projects carry a heightened degree of responsibility for companies and their directors, officers and employees. The cost of compliance with changes in governmental regulations has a potential to reduce the profitability of our operations.

If our project companies are unable to obtain adequate property rights for a project, including its interconnection rights, such project may be smaller in size or potentially unfeasible. The property rights necessary to construct and interconnect projects using our systems must also be insurable and otherwise satisfactory to the financing counterparties. Failure to obtain insurable property rights for a project satisfactory to our project companies’ financing counterparties would preclude our ability to obtain third-party financing and could prevent ongoing development and construction of such project. We could also incur losses as a result of development costs for sites that are not completed, which we would have to write off.

Current or future litigation or administrative proceedings could have a material adverse effect on our business, financial condition and results of operations.

We have been, and continue to be, involved in legal proceedings, administrative proceedings, claims and other litigation that arise in the ordinary course of business. Individuals and interest groups may choose to litigate the issuance of a permit for a solar thermal energy project or seek to enjoin construction of a solar thermal energy project, among other potential issues. For example, in January 2011, two lawsuits challenging the issuance of certain permits for Ivanpah were filed. The plaintiffs in the first proceeding allege that the permitting process for four large scale solar projects on federal land in California, including Ivanpah, did not comply with various federal requirements. The second suit was brought by the Western Watersheds Project, a non-profit organization, against the U.S. Department of

Interior, or DOI, alleging that the permitting process for Ivanpah did not comply with various federal requirements. While we believe the claims are without merit, unfavorable outcomes or developments relating to these proceedings, such as judgments for monetary damages, injunctions or denial or revocation of permits, could have a material adverse effect on our business, financial condition and results of operations. In addition, settlement of claims could adversely affect our financial condition and results of operations. See “Business—Legal Proceedings.”

We face competition from both more established renewable energy generation developers and traditional energy companies and we may not be successful in competing in this industry.

We compete with other renewable energy companies and developers as well as traditional energy companies and developers, which may have greater financial and other resources than we do. Our project companies compete with other solar companies primarily for sites with high levels of direct sunlight that can be built in a cost-effective manner, and with other energy companies for access to transmission or distribution networks. We also compete with other renewable energy developers for the limited pool of personnel with requisite industry knowledge and experience.

The solar energy market is at a relatively early stage of development, and the extent to which solar thermal technology will be widely adopted by purchasers of electricity or the EOR industry is uncertain. If our solar thermal technology proves unsuitable for widespread adoption or if demand for our solar energy systems fails to develop sufficiently, we may be unable to grow our business beyond our signed PPAs or generate sufficient sales to achieve and then sustain profitability. Renewable energy companies are competing intensely to meet the needs of utilities to provide power during periods of peak demand, in part, we believe, because utilities may be willing to pay more for reliable power on-peak than for power that is less reliable and/or delivered off-peak. Other renewable energy sources, or other technologies designed to enhance reliability of power supply during periods of peak load for utilities, may exceed our systems’ capabilities in meeting this on-peak demand. We believe our systems provide a cost-competitive solution with characteristics that are more valuable to utilities than other renewable energy technologies; however, if other sources or technologies are better able to meet the utilities’ needs, or the utilities prove unwilling to pay more for reliable on-peak power, our ability to enter highly favorable long-term PPAs in the future may be adversely affected.

Depending on the regulatory framework and market dynamics of a region, we may also compete with other renewable energy producers or traditional electricity producers when we bid on or negotiate for a long-term PPA. Furthermore, technological progress in traditional forms of electricity generation or the discovery of large new deposits of traditional fuels could reduce the cost of electricity generated from those sources and as a consequence reduce the demand for electricity from renewable energy sources, or render existing or future solar thermal energy projects uncompetitive. Any of these developments could have a material adverse effect on our business, financial condition and results of operations.

Electric power plants using our systems to generate electricity rely on national and regional transmission systems and related facilities that are owned and operated by third parties and have both regulatory and physical constraints impeding access to electric markets.

Electric power plants using our systems to generate electricity in both domestic and international regions depend on electric transmission systems and related facilities owned and operated by third parties to deliver the electricity we generate and have both regulatory and physical constraints impeding access to electric markets. Electric power plants using our systems may have limited or no access to interconnection and transmission capacity at reasonable costs or in a timely fashion, because there may not be transmission capacity available or there are many parties seeking access to the limited capacity that is available. In addition, certain PPAs we have entered into contain provisions that limit, or cap, the

maximum allowable transmission costs under such PPAs, which may have the effect of increasing total project costs for electric power plants using our systems. The inability to secure access to capacity at reasonable costs, in a timely fashion or at all, could cause delays and require renegotiation of key PPA terms. Any such increased costs and delays could, in turn, delay the commercial operation dates of, or could result in termination of the PPAs associated with, electric power plants using our systems and negatively impact our revenues and financial condition.

We may be unable to construct our solar thermal projects on time, and our construction costs could increase to levels that make a project too expensive to complete or make the return on our investment in that project less than expected.

Ivanpah is the first utility-scale solar thermal power project using our technology, and we anticipate that our subsequent projects will be more cost efficient as we gain further experience in constructing large scale projects. However, there may be delays or unexpected developments in completing our solar thermal projects, which could cause the construction costs of these projects to exceed our expectations. Projects using our systems and where we have an ownership interest may suffer significant construction delays or construction cost increases as a result of a variety of factors, including:

failure to complete interconnection to transmission networks;

failure to secure and maintain environmental and other permits or regulatory approvals;

appeals of environmental and other permits or approvals that we obtain;

failure to obtain capital;

failure to obtain all necessary rights to land access and use;

failure to receive critical components and equipment that meet our design specifications;

delays in scheduled deliveries of critical components and equipment;

failure to receive quality and timely performance from key contractors and vendors;

increases in supplier costs, including those due to unexpected increases in inflation or commodity prices;

work stoppages or shortages of skilled labor;

inclement weather conditions;

adverse environmental and geological conditions; and

force majeure or other events out of our control.

Any of these factors could give rise to construction delays and construction costs in excess of our expectations. This could prevent the project from completing construction or cause significant delays, causing defaults under the project financing agreements or under PPAs that require completion of project construction by a certain time, cause the project to be unprofitable for us or otherwise impair our business, financial condition and results of operations.

If we cannot continue to develop projects to satisfy our PPAs, our ability to sell our systems will be negatively impacted and we may have significant write-offs.

If new projects fail to be completed on an ongoing basis, we may be unable to satisfy the obligations under our PPAs. Because completing the projects in our development pipeline as anticipated, or at all, involves numerous risks and uncertainties, some projects in our portfolio may not progress to construction or may be substantially delayed. From time to time, we may have to abandon

and write-off projects on which we have started development. In addition, those projects that are constructed and begin operations may not meet investors’ return expectations due to schedule delays, cost overruns or revenue shortfalls or they may not generate the capacity that we anticipate or result in receipt of revenue from system sales in the originally anticipated time period or at all. An inability to maintain our development pipeline or to convert those projects into financially successful operating projects that purchase our system and satisfy our PPAs would have a material adverse effect on our business, financial condition and results of operations.

We may not be able to identify adequate strategic relationship opportunities, or form strategic relationships, in the future.

Strategic business relationships will be an important factor in the growth and success of our business, particularly internationally. We have entered into business partnership agreements with Alstom, one of our major stockholders, to jointly market and bid on projects to design and construct solar thermal power plants in the Middle East, Northern Africa, South Africa, Southern Europe, India and potentially other locations as we see fit. Furthermore, we recently completed a solar-to-steam EOR demonstration facility for Chevron, which is also one of our stockholders. Lastly, we selected Bechtel as the EPC contractor for Ivanpah. Bechtel also funded a portion of our equity commitment for each of the three phases of Ivanpah pursuant to a loan agreement and is providing additional preliminary engineering work in support of our development efforts on our next projects.

There are no assurances that we will be able to identify or secure additional business relationship opportunities in the future or maintain our existing relationships. Our competitors also may capitalize on such opportunities before we do. We may not be able to offer similar benefits to other companies that we would like to establish and maintain strategic relationships with which could impair our ability to establish such relationships. Moreover, identifying such opportunities could demand substantial management time and resources, and negotiating and financing relationships involves significant costs and uncertainties. If we are unable to successfully identify and execute on strategic relationship opportunities in the future, our overall growth could be impaired and our operating results could be materially adversely affected.

Negative public or community response to solar thermal projects could adversely affect widespread adoption of systems using our technology.

Negative public or community response to solar thermal energy projects could adversely affect our ability to sell our systems to projects using our technology and for our project companies to develop, construct and operate their projects. This type of negative response could lead to legal, public relations and other challenges that impede our project companies’ ability to meet our development and construction targets, achieve commercial operations for a project on schedule and generate revenues. For example, Ivanpah has been, and continues to be, the subject of administrative and legal challenges from groups concerned with potential environmental impacts (e.g., impacts on the California desert tortoise and other wildlife species affected by Ivanpah as originally proposed), archaeological or cultural impacts or impacts on the natural beauty of public lands. We expect this type of opposition to continue as we develop and construct existing and future projects using our systems. An increase in opposition to our requests for permits or successful challenges or appeals to permits issued to us could materially adversely affect our development plans. If we are unable to develop and construct the production capacity to the scale that we expect from our development projects in our anticipated timeframes, our business, financial condition and results of operations could be materially adversely affected.

Our industry is characterized by a limited number of purchasers for utility-scale quantities of electricity and solar steam, which restricts our ability to negotiate PPAs and solar-to-steam contracts and could expose us and projects that use our systems to additional risk.

Our industry has a limited number of possible purchasers for utility-scale quantities of electricity in a given geographic location, including investor-owned power companies, public utility districts and cooperatives, as well as a limited number of possible purchasers for utility-scale quantities of solar steam that are located in areas in which we could economically produce that steam. As a result, there is a concentrated pool of potential buyers for projects using our systems that generate utility-scale quantities of electricity or solar steam, which may restrict our ability to negotiate favorable terms under new PPAs or solar-to-steam contracts and could impact our ability to find new customers for our system sales. Furthermore, if the financial condition of these utilities, power purchasers and/or steam purchasers deteriorated or the RPS and climate change programs to which they are currently subject changed, demand for electricity or solar steam generated by projects using our systems could be negatively impacted. The willingness of utilities to purchase electricity from an independent power producer may be based on a number of factors and not solely on pricing and predictability of supply. If we cannot enter into PPAs or solar-to-steam contracts on terms favorable to us, or at all, it would negatively impact our revenue and our decisions regarding development of additional projects to support sales of our systems.

Some of our PPAs have not yet been approved by the California Public Utilities Commission.

In order to be fully effective, each of our PPAs must be approved by the California Public Utilities Commission, or CPUC. It is the obligation of the utility entering into the PPA to obtain such approval. Through our project companies, we have 13 executed and outstanding PPAs with PG&E and SCE. Three of the PPAs are associated with Ivanpah and have been approved by the CPUC, and we retain 10 PPAs to deliver approximately 2.0 GW of installed capacity, of which five have been approved by the CPUC. With respect to the remaining PPAs requiring CPUC approval, in October 2011, we executed five amended and restated PPAs with SCE. These PPAs were submitted to the CPUC for approval in November 2011. If the five amended and restated PPAs are not approved by the CPUC, they will be subject to termination by either party thereto, which could adversely affect our business, financial condition and results of operations.

Pursuant to the terms of each of our existing PPAs, the failure to fulfill the performance requirements may result in the imposition of penalties or termination of the PPA.

Pursuant to the terms of the PPAs that we have entered into with PG&E and SCE, under which project companies we have formed will sell electrical output, we have deposited funds under each PPA to secure the respective project company’s obligations thereunder. The amounts we have deposited under each of our ten existing PPAs that are not associated with Ivanpah range up to $7 million, with total deposits of approximately $51 million to date. If we do not meet certain development milestones specified in the PPAs, the project company may be declared to have committed an event of default under the PPA and the entire deposit amount may be forfeited as a penalty for failure to perform. If an event of default occurs, and we are unable to renegotiate the terms of the PPA, the PPA may be terminated. Any renegotiation of a PPA may result in terms that are less favorable to us. After we sell majority control of a project company to third parties, the related PPA security deposits are the responsibility of the project company and its owners. However, any forfeiture and event of default, or termination, whether before or after we sell majority control of the project company to third parties, could materially and adversely affect our financial condition and cash flow.

The Ivanpah Treasury Cash Grant could be recaptured by the government.

The economics of Ivanpah are heavily influenced by the assumed full receipt of U.S. Department of the Treasury cash grants, or Treasury Cash Grant, aggregating approximately $570 million. The U.S. Treasury is generally required to pay the Treasury Cash Grant by the later of sixty days after a project is placed into service or sixty days after the date on which an application is submitted. After receiving a Treasury Cash Grant, the grant may be recaptured by the government if, within five years of the date the project is placed in service, any interest in the project or company is transferred to certain prohibited persons, the equipment ceases to be specified energy property or the equipment is taken out of service (other than due to an “act of God”). Specified energy property includes only tangible property (not including a building or its structural components) for which depreciation, or amortization in lieu of depreciation, is allowable. The Treasury Cash Grant program currently is available only to projects that commence construction by December 31, 2011, and this program may not be extended to future projects.

There is no guarantee that the Treasury or the tax law will recognize the cost basis that we claim in a project’s specified energy property. If the Treasury concludes that the true cost of any specified energy property is lower than the cost of that property claimed by the project companies in which we have an ownership interest, then Treasury may seek to reduce the amount of the Treasury Cash Grant that it pays to the project.

We are subject to credit and performance risk from third parties under service and supply contracts.

We enter into contracts with vendors to supply equipment, materials and other goods and services for our proprietary technology and the development and construction of solar thermal energy projects. If vendors do not perform their obligations, we may have to enter into new contracts with other vendors at a higher cost or may have schedule disruptions affecting the amount of time and expense required to complete a project. For example, some of our key components for Ivanpah, including boilers from Riley and turbines from Siemens, are available from a limited or sole source of supply. Replacement of these components, where possible, may involve long lead times and result in a delay in fulfilling our obligations to projects using our systems.

When we purchase third-party solar system components, we also enter into warranty agreements with the manufacturer. However, there can be no assurance that the manufacturer will be able to fulfill its contractual obligations. In addition, these warranties generally expire within 12 to 24 months after the component delivery date or the date the component is commissioned. If we seek warranty protection and the manufacturer is unable or unwilling to perform its obligations under the warranty, whether as a result of the manufacturer’s financial condition or otherwise, or if the term of the warranty has expired, we may suffer reduced warranty availability for the affected components, which could have a material adverse effect on our business, financial condition and results of operations. Also, under such warranties, the warranty payments by the manufacturer are typically subject to an aggregate maximum cap that is a portion of the total purchase price of the components. Losses in excess of these caps may be our responsibility.

The loss of one or more members of our senior management or key employees may adversely affect our ability to implement our strategy.

We depend on our experienced management team and the loss of one or more key executives could have a negative impact on our business. We also depend on our ability to retain and motivate key employees and attract qualified new employees. Because the utility-scale solar industry is relatively new, there is a scarcity of top-quality employees with requisite experience, especially experience in the solar thermal energy industry. If we lose a member of the management team or a key

employee, we may not be able to replace him or her. Integrating new employees into our management and engineering teams and training new employees with no prior experience in the solar thermal energy industry could prove disruptive to our operations, require a disproportionate amount of resources and management attention and ultimately prove unsuccessful. An inability to attract and retain sufficient technical and managerial personnel could limit or delay our development efforts, which could have a material adverse effect on our business, financial condition and results of operations.

The materials and equipment we provide to Ivanpah will be warranted by us to be free of defects in workmanship and materials for a period of 48 months following the achievement of substantial completion under the EPC contract applicable to each Ivanpah project. All warranty work includes the cost of removal, disassembly, repair, replacement and reassembly of the warranted items. Repaired or replaced work is re-warranted for an additional twelve-month period or the remainder of the original 48-month warranty period, whichever is longer, subject to a limitation that no warranty shall extend beyond 12 months following expiration of the original 48-month warranty period. We guarantee that each solar field and boiler at Ivanpah will provide sufficient steam output (at specified steam conditions set forth in the applicable EPC contract) to achieve substantial completion by the guaranteed substantial completion date. We further guarantee the achievement of at least 95% of projected plant electrical generation during at least one of the first four years of commercial operation. This guarantee excludes lost electrical generation unrelated to the solar energy system design, solar field equipment or the boiler, due to the impact of weather conditions, or due to work or services provided by others (not under subcontract to BrightSource), but will not be subject to any sublimit of liability other than the aggregate limitation of liability (100% of the contract value) under each solar field agreement between us and the project. In addition, we will provide a 48-month serial defect warranty with respect to the pylons, mirrors, pad bonds, worm and elevation drives. In the event that 20% of any such warranted items have an identical defect, a rebuttable presumption will arise that 100% of all such items are defective.

Because of the limited operating history of our solar thermal systems, we have been required to make assumptions and apply judgments regarding a number of factors, including our anticipated rate of warranty claims, the durability and reliability of our systems and the performance of our equipment, including heliostats in the field. Our assumptions could prove to be materially different from the actual long-term performance of our systems, resulting in significant operational problems for us including increased maintenance costs and inability to meet energy delivery requirements or defaults under project or financing documents. Any widespread system or component failures may damage our market reputation and cause our revenue to decline.

The production of solar energy depends heavily on suitable meteorological conditions. If solar conditions are unfavorable, our electricity production, and therefore revenue from projects using our systems, may be substantially below our expectations.

The electricity produced and revenues generated by a solar energy project will be highly dependent on suitable solar conditions and associated weather conditions, which are beyond our control. Furthermore, components of our system, such as the heliostats, could be damaged by severe weather, such as hailstorms or tornadoes. Unfavorable weather and atmospheric conditions could impair the effectiveness or require shutdown of key equipment, impeding operation of our projects, which would result in reduced energy production and decreased revenues and, if these problems persist, potential payments, deductions or defaults under key project documents, including our projects’ PPAs or other financing arrangements.

In the long term, we intend to expand our international activities, which will subject us to a number of risks.

Our long-term strategic plans include international expansion, such as through our pre-disclosed partnership with Alstom to jointly market and bid on projects in the Middle East, Northern Africa, South Africa, Southern Europe and India. We intend to sell our proprietary technology system and develop, construct and sell our solar thermal system in international locations. Risks inherent to international operations include the following:

inability to work successfully with third parties having local expertise to co-develop international projects;

multiple, conflicting and changing laws and regulations, including export and import restrictions, tax laws and regulations, environmental regulations, labor laws and other government requirements, approvals, permits and licenses;

difficulties in enforcing agreements in foreign legal systems;

changes in general economic and political conditions in the countries in which we operate, including changes in government incentives relating to power generation and solar electricity;

political and economic instability, including wars, acts of terrorism, political unrest, boycotts, curtailments of trade and other business restrictions;

difficulties and costs in recruiting and retaining individuals skilled in international business operations;

international business practices that may conflict with U.S. customs or legal requirements;

financial risks, such as longer sales and payment cycles and greater difficulty collecting accounts receivable;

fluctuations in currency exchange rates relative to the U.S. dollar; and

inability to obtain, maintain or enforce intellectual property rights.

Doing business in foreign markets requires us to be able to respond to rapid changes in market, legal, and political conditions in these countries. The success of our business will depend, in part, on our ability to succeed in differing legal, regulatory, economic, social and political environments. We may not be able to develop and implement policies and strategies that will be effective in each location where we do business.

Political, economic and security conditions in Israel, where all of the product research and development, engineering services and solar field supply chain management for our systems are located, may adversely affect our operations and may limit our ability to sell our systems.

Our Israeli subsidiary provides substantially all of the product research and development, engineering services and procurement functions for our systems, including heliostats, solar boilers and control systems for all of our solar fields. Political, economic and security conditions in Israel directly affect our subsidiary employees and operations. There has been ongoing violence, primarily in the West Bank and Gaza Strip. We could be adversely affected by hostilities involving Israel, the interruption or curtailment of trade between Israel and its trading partners or a significant downturn in the economic or financial condition of Israel. In addition, the sale of products manufactured in Israel may be adversely affected in certain countries by restrictive laws, policies or practices directed toward Israel or companies having operations in Israel.

In addition, some of our employees in Israel are subject to being called on to perform military service and their absence may have an adverse effect upon our operations. Generally, unless exempt,

male adult citizens of Israel under the age of 41 are obligated to perform up to 36 days of military reserve duty annually and all such citizens are subject to being called to active duty at any time under emergency circumstances.

These events and conditions could disrupt our operations in Israel, which could materially harm our business, financial condition, future results and cash flow.

We are an international organization and we could be obligated to pay taxes in various jurisdictions.

Historically, our foreign operations have been located in Israel, but we anticipate expanding into other foreign jurisdictions in the future. As an international organization we will be subject to taxation in foreign jurisdictions with increasingly complex tax laws, the application of which can be uncertain. The amount of taxes we pay in these jurisdictions could increase substantially as a result of changes in the applicable tax principles, including increased tax rates, new tax laws or revised interpretations of existing tax laws and precedents, which could have a material adverse effect on our liquidity and results of operations. In addition, the authorities in these jurisdictions could review our tax returns and impose additional tax, interest and penalties, and the authorities could claim that various withholding requirements apply to us or our subsidiaries or assert that benefits of tax treaties are not available to us or our foreign subsidiaries, any of which could have a material impact on us and the results of our operations.

Taxing authorities could reallocate our taxable income among our subsidiaries which could increase our consolidated tax liability.

We intend to conduct operations worldwide through subsidiaries in various tax jurisdictions. If two or more affiliated companies are located in different countries, the tax laws or regulations of each country generally will require that transfer prices be the same as those between unrelated companies dealing at arm’s length and that contemporaneous documentation is maintained to support the transfer prices. On that basis, tax authorities could require us to adjust our transfer prices and thereby reallocate our income to reflect these revised transfer prices, which may result in a higher tax liability to us and possibly result in two countries taxing the same income, which could adversely affect our financial condition, results of operations and cash flows.

Proposed and enacted U.S. federal income tax legislation could negatively impact our effective tax rate.

Recent changes to U.S. tax law as well as other proposed tax legislation that could be enacted in the future could substantially impact the tax treatment of our non-U.S. earnings. These proposed and enacted changes include limitations on the ability to claim and utilize foreign tax credits and deferral of interest expense deductions until non-U.S. earnings are repatriated to the United States. Such legislation could negatively impact the amount of taxes payable in the United States and our effective tax rate and possibly adversely affect our results of operations.

Our business will be adversely affected if we are unable to protect our intellectual property rights from unauthorized use or infringement by third parties.

Any failure to protect our proprietary rights adequately could result in our competitors offering similar solar thermal technology more quickly than anticipated, potentially resulting in the loss of some of our competitive advantage and a decrease in our revenue which would adversely affect our business prospects, financial condition and operating results. Our success depends, at least in part, on our ability to protect our core technology and intellectual property. We primarily rely on a combination of trade secrets and contractual rights, including employee and third-party nondisclosure agreements,

to protect our proprietary information and know-how. We also maintain a growing patent portfolio that currently consists of nine issued U.S. patents (including one patent covering dynamic system optimization and another covering integration of solar thermal systems and PV, both of which were issued by the U.S. Patent and Trademark Office in the second half of 2011, and one patent covering heliostat and receiver design) and numerous patent applications including 11 patent applications covering solar field optimization and control, five patent applications covering our operating methods, six patent applications covering heliostat and receiver design and three patent applications covering thermal energy storage.

The protection provided by the intellectual property laws and contractual rights may be important to our future opportunities. However, the measures we take to protect our intellectual property from use by others afford only limited protection and may not be effective. In addition, the laws of some foreign countries do not protect our proprietary rights to the same extent as do the laws of the United States, and policing the unauthorized use of our intellectual property is difficult.

We may be exposed to infringement or misappropriation claims by third parties, which, if determined adversely to us, could cause us to pay significant damage awards or prohibit us from the construction and sale of our solar thermal facilities or the use of our value added system technology.

The technology incorporated into and used to develop and construct our current and future systems may be subject to claims that they infringe the patents or proprietary rights of others. Should the outcome of any such claims be unfavorable, we could be required to pay the plaintiff(s) damages and potentially be enjoined from using what the plaintiff(s) claim is their property or confidential information unless we enter into a mutually suitable arrangement. As a result, the financial condition, results of operations and cash flows of our projects could be materially and adversely affected. Third parties may allege that our projects infringe patents, trademarks or copyrights, or that we have misappropriated trade secrets, and such parties could have significantly more resources to devote to any resulting enforcement actions. These allegations could result in significant costs and diversion of the attention of management. If a claim were brought against us, and we were found to have infringed upon a third party’s intellectual property rights, we could be required to pay substantial damages, including treble damages, or be enjoined from using the technology deemed to be infringing or using or constructing systems deemed to be infringing. In addition, we may need to attempt to license the intellectual property rights from the patent holder or spend time and money to design around or avoid the intellectual property infringement. Any such license may not be available on reasonable terms, or at all, and efforts to design around or avoid the intellectual property may be unsuccessful.

We, our partners and project companies may rely on specialized structured financing arrangements to realize the benefits provided by ITCs and accelerated tax depreciation. These arrangements may limit the cash distributions we receive.

Our project companies may enter into tax equity financing transactions in which they would receive investments from tax equity investors when our projects are placed in service in return for tax benefits in our project companies. Until the tax equity investors achieve their agreed upon rate of return, they may be entitled to substantially all of the applicable project’s operating cash flow from electricity sales and related hedging activities, as well as substantially all of the project’s ITCs, accelerated depreciation and taxable income or loss. Typically, project sponsors structure tax equity financing transactions so that the tax equity investors reach their target return between five and ten years after the applicable project achieves commercial operation.

As a result, a tax equity financing may substantially reduce the cash distributions from the applicable project available to us for other uses, and the period during which the tax equity investors

receive most of the cash distributions from electricity sales may last longer than expected if our solar thermal energy projects perform below our expectations.

The ability of our project companies to enter into tax equity arrangements in the future depends heavily on the extension of the expiration date or renewal of the ITCs, without which the market for tax equity financing would possibly cease to exist. Moreover, there is a limited amount of tax equity investment capital and a limited number of potential tax equity investors. Solar thermal energy developers must compete with other renewable energy developers and others for tax equity financing. In addition, conditions in financial and credit markets generally may result in the contraction of available tax equity financing. As the renewable energy industry expands, the cost of tax equity financing may increase and there may not be sufficient tax equity financing available to meet the total demand in any year. If our project companies are unable to enter into tax equity financing agreements with attractive pricing terms or at all, they may not be able to use the tax benefits provided by ITCs and accelerated tax depreciation in the manner they do so today, which could have a material adverse effect on our business, financial condition and results of operations.

Changes to financial accounting standards may affect our results of operations and cause us to change our business practices.

We prepare our financial statements in accordance with accounting principles generally accepted in the United States, or GAAP. These accounting principles are subject to interpretation by the Financial Accounting Standards Board, the SEC and various bodies formed to interpret and create appropriate accounting policies. A change in these accounting standards or the questioning of current reporting practices may adversely affect our reported financial results or the way we conduct our business.

We are not able to insure against all potential risks and may become subject to higher insurance premiums.

Our business is exposed to the risks inherent in the development, construction and operation of solar thermal energy projects, such as breakdowns, manufacturing defects, natural disasters, terrorist attacks and sabotage. We are also exposed to environmental risks. We have insurance policies covering certain risks associated with our business. Our insurance policies, however, do not cover losses as a result of force majeure, natural disasters, terrorist attacks or sabotage, among other things. We generally do not maintain insurance for certain environmental risks, such as environmental contamination. In addition, our insurance policies are subject to annual review by our insurers and may not be renewed at all or on similar or favorable terms. A serious uninsured loss or a loss significantly exceeding the limits of our insurance policies or the failure to renew our insurance policies on similar or favorable terms could have a material adverse effect on our business, financial condition and results of operations.

Our ability to use our net operating losses to offset future taxable income may be subject to certain limitations.

In general, under Section 382 of the Code, a corporation that undergoes an “ownership change” is subject to limitations on its ability to utilize its pre-change net operating losses, or NOLs, to offset future taxable income. Our existing NOLs may be subject to limitations arising from previous ownership changes, and if we undergo an ownership change in connection with or after this offering, our ability to utilize NOLs could be further limited by Section 382 of the Code. Future changes in our stock ownership, some of which are beyond our control, could result in an ownership change under Section 382 of the Code. Furthermore, our ability to utilize NOLs of any companies that we may acquire in the future may be subject to limitations. For these reasons, we may not be able to utilize a material portion of the NOLs reflected on our balance sheet, even if we attain profitability.

Our largely unproven mirror cleaning equipment may perform below our expectations.

The primary maintenance activity for solar thermal projects using our systems will be the routine and continuous washing of reflective mirror surfaces. We anticipate each mirror may need to be cleaned every two weeks to prevent a buildup of dust which would significantly degrade the system performance. Mirrors will be washed at night by a dedicated crew using specialized mobile equipment. A truck is being designed that will bring purified water simultaneously to a number of mirrors. We are still designing and testing the specialized equipment to be used in this process. If the mirror washing equipment and process are not effective, actual operating costs may be substantially higher than forecasted or total electrical production may fall short of estimates.

Our headquarters and some of our development sites are located in active earthquake zones, and an earthquake or other types of natural disasters affecting us or our suppliers could cause resource shortages and disrupt and harm our results of operations.

We conduct our executive and administrative operations in the San Francisco Bay Area, which is an active earthquake zone, and certain of our project companies, development sites and suppliers conduct their operations in the same region or in other locations that are susceptible to natural disasters. In addition, California and some of the locations where certain of our suppliers are located, from time to time, have experienced shortages of water, electric power and natural gas. The occurrence of a natural disaster, such as an earthquake, drought, flood or localized extended outages of critical utilities or transportation systems, or any critical resource shortages, affecting us or our suppliers, could cause a significant interruption in our business, damage or destroy our facilities or those of our suppliers or the manufacturing equipment or inventory of our suppliers, and cause us to incur significant costs, any of which could harm our business, financial condition and results of operations. The insurance we maintain against fires, earthquakes and other natural disasters may not be adequate to cover our losses in any particular case.

Risks Related to This Offering and Ownership of Our Common Stock

Our share price may be volatile and you may be unable to sell your shares at or above the initial public offering price.

The initial public offering price for our shares will be determined by negotiations between us and representatives of the underwriters and may not be indicative of prices that will prevail in the trading market. The market price of shares of our common stock could be subject to wide fluctuations in response to many risk factors listed in this section, and others beyond our control, including:

actual or anticipated fluctuations in our financial condition and operating results;

unanticipated development or construction delays or other changes in our project plans;

announcements of technological innovations or new products by us or our competitors;

adverse announcements regarding systems performance;

reductions in the retail price of electricity, to the extent projects are negotiating PPAs;

additions or departures of key personnel;

the failure of securities analysts to cover our common stock after this offering or updates or changes in financial estimates or recommendations by securities analysts;

the inability to meet the financial estimates of securities analysts;

fluctuations in the valuation of companies perceived by investors to be comparable to us;

disputes or other developments related to our intellectual property rights, including litigation, and our ability to obtain and maintain patent protection for our technology;

changes in laws, regulations and policies applicable to our business and products, particularly those relating to government incentives for solar energy;

announcement or expectation of additional financing efforts;

sales of our common stock by us or our stockholders;

market conditions in our industry and industries of our customers; and

general economic and market conditions.

Furthermore, the stock markets have experienced extreme price and volume fluctuations that have affected and continue to affect the market prices of equity securities of many companies. These fluctuations often have been unrelated or disproportionate to the operating performance of those companies. These broad market and industry fluctuations, as well as general economic, political and market conditions such as recessions, interest rate changes or international currency fluctuations, may negatively impact the market price of shares of our common stock. If the market price of shares of our common stock after this offering does not exceed the initial public offering price, you may not realize any return on your investment in us and may lose some or all of your investment. In the past, certain companies that have experienced volatility in the market price of their stock have been subject to securities class action litigation. We may be the target of this type of litigation in the future. Securities litigation against us could result in substantial costs and divert our management’s attention from other business concerns, which could seriously harm our business.

There has been no prior market for our common stock and an active trading market may not develop.

Prior to this offering, there has been no public market for our common stock. An active trading market may not develop following the completion of this offering or, if developed, may not be sustained. The lack of an active market may impair your ability to sell your shares of common stock at the time you wish to sell them or at a price that you consider reasonable. The lack of an active market may also reduce the fair market value and increase the volatility of your shares of common stock. An inactive market may also impair our ability to raise capital by selling shares of common stock and may impair our ability to acquire other companies or technologies by using our shares of common stock as consideration.

We expect to incur increased costs and our management will face increased demands as a result of operating as a public company, including the costs to establish and maintain effective internal controls and remediate an existing material weakness.

We have never operated as a public company. As a public company, we will incur significant legal, accounting, internal controls over financial reporting and other expenses that we did not incur as a private company. In addition, the Sarbanes-Oxley Act of 2002, or the Sarbanes-Oxley Act, the Dodd-Frank Wall Street Reform and Consumer Protection Act, as well as related rules implemented by the SEC, and The Nasdaq Stock Market, impose various requirements on public companies. Our management and other personnel will need to devote a substantial amount of time to these compliance initiatives. Moreover, these rules and regulations will increase our legal and financial compliance costs and will make some activities more time-consuming and costly. For example, we expect these rules and regulations to make it more expensive for us to maintain director and officer liability insurance. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of director or as our executive officers.

In addition, the Sarbanes-Oxley Act requires, or will require, among other things, that we maintain effective internal control over financial reporting and disclosure controls and procedures. In particular, we will be required to perform system and process evaluation and testing of our internal control over

financial reporting to allow management and our independent registered public accounting firm to report on the effectiveness of our internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act. For example, we and our independent registered public accounting firm have identified a material weakness in our internal controls over financial reporting relating to the preparation of our consolidated statement of cash flows that has resulted in restatements to historical financial statements. We are currently in the process of remediating the material weakness. Our remediation plan includes, among other things, hiring additional accounting staff, enhancing our internal review procedures during the financial statement close process, providing additional technical training to key finance and accounting personnel and updating related control procedures to specifically address the identified control deficiencies. These activities are ongoing and management anticipates completing our remediation activities during the first half of 2012. Remediating this material weakness and maintaining proper and effective internal controls will require substantial management time and attention and may result in our incurring substantial incremental expenses.

In future periods, if the process required by Section 404 of the Sarbanes-Oxley Act or other evaluation and testing of our internal controls reveal any other material weaknesses or significant deficiencies, the correction of any such material weaknesses or significant deficiencies could require additional remedial measures or future restatements that could be costly and time-consuming. In addition, we cannot be certain that restatements will not occur in the future. Any restatements could create a strain on our internal resources and cause delays in our filing of quarterly or annual financial results. Failure to have effective internal financial and accounting controls could cause our financial reporting to be unreliable, and we may be unable to produce accurate financial reporting and disclosures on a timely basis. Any of the foregoing could cause investors to lose confidence in our consolidated financial statements, resulting in a material adverse effect on our business, reputation, results of operations, financial condition or liquidity, which could have a material adverse effect on the price of our common stock.

Concentration of ownership among our existing executive officers, directors and their affiliates may prevent new investors from influencing significant corporate decisions.

Upon completion of this offering, our executive officers, directors and their affiliates will beneficially own, in the aggregate, approximately % of our outstanding shares of common stock. In particular, VantagePoint Capital Partners will beneficially own approximately % and Alstom will beneficially own approximately % of our outstanding shares of common stock upon completion of this offering. As a result, these stockholders will be able to exercise a significant level of control over all matters requiring stockholder approval, including the election of directors, amendment of our certificate of incorporation and approval of significant corporate transactions. This control could have the effect of delaying or preventing a change of control of our company or changes in management and will make the approval of certain transactions difficult or impossible without the support of these stockholders.

Anti-takeover provisions in our charter documents and Delaware law, as well as restrictions and covenants in our DOE-guaranteed loan facility, could discourage, delay or prevent a change in control of our company and may affect the trading price of our common stock.

Our amended and restated certificate of incorporation and bylaws to be effective upon the completion of this offering will contain provisions that could have the effect of rendering more difficult or discouraging an acquisition deemed undesirable by our board of directors. Our corporate governance documents will include the following provisions:

authorizing blank check preferred stock, which could be issued with voting, liquidation, dividend and other rights superior to our common stock;

limiting the liability of, and providing indemnification to, our directors and officers;

limiting the ability of our stockholders to call and bring business before special meetings and to take action by written consent in lieu of a meeting;

requiring advance notice of stockholder proposals for business to be conducted at meetings of our stockholders and for nominations of candidates for election to our board of directors;

establishing a classified board of directors, as a result of which the successors to the directors whose terms have expired will be elected to serve from the time of election and qualification until the third annual meeting following their election;

requiring that directors only be removed for cause; and

limiting the determination to our board of directors then in office with respect to the number of directors on our board and the filling of vacancies or newly created seats on the board.

As a Delaware corporation, we are also subject to provisions of Delaware law, including Section 203 of the Delaware General Corporation Law, which prevents some stockholders holding more than 15% of our outstanding common stock from engaging in certain business combinations without the prior approval of our board of directors or the holders of substantially all of our outstanding common stock.

These provisions of our charter documents and Delaware law, alone or together, could delay or deter hostile takeovers and changes in control or changes in our management. Any provision of our amended and restated certificate of incorporation or bylaws or Delaware law that has the effect of delaying or deterring a change in control could limit the opportunity for our stockholders to receive a premium for their shares of our common stock. Even in the absence of a takeover attempt, the existence of these provisions may adversely affect the prevailing market price of our common stock if they are viewed as discouraging takeover attempts in the future.

Purchasers in this offering will experience immediate and substantial dilution in the book value of their investment.

The initial public offering price of our common stock is substantially higher than the net tangible book value per share of our outstanding common stock immediately after this offering. Therefore, if you purchase our common stock in this offering, you will experience immediate and substantial dilution of your investment. Based upon the issuance and sale of shares of common stock by us at an assumed initial public offering price of $ per share (the midpoint of the price range set forth on the cover of this prospectus), you will incur immediate dilution of approximately $ in the pro forma net tangible book value per share if you purchase shares of our common stock in this offering.

As of December 31, 2011, we had outstanding options and warrants to purchase approximately shares of common stock with exercise prices that are below the assumed initial public offering price of the common stock. To the extent that these options and warrants are exercised, you will experience further dilution.

You may experience dilution of your ownership interest due to the future issuance of additional shares of our common stock.

We are in a capital intensive business, and may not have sufficient funds to finance the growth of our business, the construction costs of our development projects or to support our projected capital expenditures. As a result, we will require additional funds from further equity or debt financings, including tax equity financing transactions or sales of preferred shares or convertible debt to complete the development of new projects and pay the general and administrative costs of our business. In the future, we may issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of purchasers of common stock offered hereby. Under our amended and restated

certificate of incorporation and bylaws, we will be authorized to issue shares of common stock and shares of preferred stock with preferences and rights as determined by our board of directors. The potential issuance of additional shares of common stock or preferred stock or convertible debt may create downward pressure on the trading price of our common stock. We may also issue additional shares of common stock or other securities that are convertible into or exercisable for common stock in future public offerings or private placements for capital raising purposes or for other business purposes, potentially at an offering price, conversion price or exercise price that is below the offering price for common stock in this offering.

A significant portion of our total outstanding shares may be sold into the public market in the future, which could cause the market price of our common stock to drop significantly, even if our business is doing well.

Sales of a substantial number of shares of our common stock in the public market could occur at any time after the expiration of the lock-up agreements described in the “Underwriting” and “Shares Eligible for Future Sale” sections of this prospectus. These sales, or the market perception that the holders of a large number of shares intend to sell shares, could reduce the market price of our common stock. After this offering, we will have shares of common stock outstanding (assuming an initial public offering price at the midpoint of the range set forth on the cover of this prospectus). This includes the shares that we are selling in this offering (plus any shares issued upon exercise of the underwriters’ overallotment option), which may be resold in the public market immediately. The remaining shares, or % of our outstanding shares after this offering, are currently restricted as a result of securities laws or lock-up agreements but will be able to be sold, subject to any applicable volume limitations under federal securities laws, in the near future as set forth below:

shares will be eligible for sale immediately upon completion of this offering; and

shares will be eligible for sale upon the expiration of lock-up agreements, subject in some cases to volume and other restrictions of Rule 144 and Rule 701 under the Securities Act of 1933, as amended, or the Securities Act.

The lock-up agreements expire 180 days after the date of this prospectus, except that the 180-day period may be extended in certain cases for up to 33 additional days under certain circumstances where we announce or pre-announce earnings or a material event occurs within 17 days prior to, or 15 days after, the termination of the 180-day period. Goldman, Sachs & Co. may, with our consent, and at any time without notice, release all or any portion of the securities subject to lock-up agreements.

Following this offering, holders of shares of our common stock not sold in this offering and holders of warrants to purchase an aggregate of shares of common stock not sold in this offering will be entitled to rights with respect to the registration of these shares under the Securities Act. See “Description of Capital Stock—Registration Rights.” If we register their shares of common stock following the expiration of the lock-up agreements, these stockholders could sell those shares in the public market without being subject to the volume and other restrictions of Rule 144 and Rule 701.

After the completion of this offering, we intend to register approximately shares of common stock that have been reserved for future issuance under our stock incentive plans. Of these shares, shares will be eligible for sale upon the exercise of outstanding options that will be vested after the expiration of the lock-up agreements.

If securities or industry analysts do not publish or cease publishing research or reports about us, our business or our market, or if they change their recommendations regarding our stock adversely, our stock price and trading volume could decline.

The trading market for our common stock will be influenced by the research and reports that industry or securities analysts may publish about us, our business, our market or our competitors. If

any of the analysts who may cover us change their recommendation regarding our stock adversely, or provide more favorable relative recommendations about our competitors, our stock price would likely decline. If any analyst who may cover us were to cease coverage of our company or fail to regularly publish reports on us, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline.

Our management will have broad discretion over the use of the proceeds we receive in this offering and might not apply the proceeds in ways that increase the value of your investment.

Our management will have broad discretion over the use of the net proceeds from this offering, and you will be relying on their judgment in applying these proceeds. Our management might not apply our net proceeds in ways that ultimately increase the value of your investment. At this time, we have not identified specific uses for the proceeds. However, we currently expect to use the net proceeds from this offering for working capital, capital expenditures and general corporate purposes. Our management might not be able to yield a significant return, if any, on any investment of these net proceeds. You will not have the opportunity to influence our decisions on how to use our net proceeds from this offering.

After the completion of this offering, we do not expect to declare any dividends in the foreseeable future.

After the completion of this offering, we do not anticipate declaring any cash dividends to holders of our common stock in the foreseeable future. Consequently, investors may need to rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize any future gains on their investment. Investors seeking cash dividends should not purchase our common stock.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus includes forward-looking statements. We have based these forward-looking statements largely on our current expectations and projections about future events and financial trends affecting the financial condition of our business. Forward-looking statements should not be read as a guarantee of future performance or results, and will not necessarily be accurate indications of the times at, or by, which such performance or results will be achieved. Forward-looking statements are based on information available at the time those statements are made and/or management’s good faith belief as of that time with respect to future events, and are subject to risks and uncertainties that could cause actual performance or results to differ materially from those expressed in or suggested by the forward-looking statements. Important factors that could cause such differences include, but are not limited to:

the performance of our proprietary technology, which has a short history, when implemented on utility-scale projects;

the successful implementation of Ivanpah, the first utility-scale solar thermal power plant using our technology, as well as the Coalinga Solar-to-Steam for EOR project;

our ability to finance the growth of our business, including the development and construction of solar thermal energy projects using our systems;

our dependence on federal, state and local government support for renewable energy sources, which are subject to change;

our ability to further refine and develop improved technologies;

locating sites, securing site control and permitting suitable operating sites for projects using our systems;

our ability to compete against more established renewable energy generation developers as well as traditional energy companies;

our ability to procure and maintain the permits necessary to construct projects;

our ability to identify adequate strategic relationship opportunities or form strategic relationships in the future;

our ability to timely fulfill our obligations under our existing power purchase agreements;

the attraction and retention of qualified employees and key personnel;

our ability to successfully navigate the risks related to international expansion;

the political, economic and security conditions in Israel where all of the product development, engineering services and solar field supplies for our system are located;

our ability to protect our intellectual property; and

other risk factors included under “Risk Factors” in this prospectus.

In addition, in this prospectus, the words “believe,” “may,” “estimate,” “continue,” “anticipate,” “intend,” “expect,” “predict,” “potential” and similar expressions, as they relate to our company, our business and our management, are intended to identify forward-looking statements. In light of these risks and uncertainties, the forward-looking events and circumstances discussed in this prospectus may not occur and actual results could differ materially from those anticipated or implied in the forward-looking statements.

Forward-looking statements speak only as of the date of this prospectus. You should not put undue reliance on any forward-looking statements.

USE OF PROCEEDS

We estimate that we will receive net proceeds from this offering of approximately $ million ($ if the underwriters’ option to purchase additional shares is exercised in full) based on an assumed initial public offering price of $ per share (the midpoint of the price range set forth on the cover of this prospectus) and after deducting underwriting discounts and commissions and estimated offering expenses of approximately $ million. The principal purposes of this offering are to obtain additional capital, create a public market for our common stock, and facilitate our future access to the public equity markets. We currently intend to use the additional capital obtained from this offering for working capital, capital expenditures and general corporate purposes, which may include domestic and international development activities, hiring additional personnel and investing in research and development. The amounts and timing of our actual expenditures will depend on numerous factors, including the status of our development activities and the amount of cash generated or used by our operations.

As of the date of this prospectus, we cannot specify all of the particular uses for the net proceeds from this offering. We will have broad discretion over the uses of the net proceeds in this offering. Pending specific uses, we intend to invest the net proceeds from the offering in interest-bearing, investment grade securities.

DIVIDEND POLICY

We have never declared or paid cash dividends on our capital stock. We currently intend to retain all available funds and any future earnings for use in the operation of our business and do not anticipate paying any cash dividends in the foreseeable future. Our term loan contains limitations on our ability to issue dividends.

CAPITALIZATION

The following table sets forth cash and cash equivalents and our capitalization as of September 30, 2011:

on an actual basis;

on a pro forma basis to reflect (i) the conversion of all of our shares of convertible preferred stock outstanding as of September 30, 2011 into 79,135,944 shares of common stock upon the completion of this offering (which does not give effect to any additional shares of common stock issuable upon conversion of the Series E preferred stock, as described below); (ii) the exercise of warrants to purchase 60,387 shares of Series A preferred stock in December 2011; and (iii) the effectiveness of our amended and restated certificate of incorporation in Delaware immediately prior to the completion of this offering; and

Our capitalization following the closing of this offering may be adjusted based upon the actual initial public offering price and other terms of the offering determined at pricing. The number of shares of our common stock actually issued upon the conversion of our outstanding shares of Series E preferred stock, which will occur immediately prior to the completion of this offering, depends in part on the actual initial offering price of our common stock in this offering. The terms of our Series E preferred stock provide that the ratio at which each share of Series E preferred stock automatically converts into shares of our common stock in connection with a qualified IPO (for which this offering will qualify) will increase if the initial offering price per share of common stock in the qualified IPO is below a specified minimum dollar amount, which would result in additional shares of common stock being issued upon conversion of the Series E preferred stock. In the event the actual initial public offering price is lower than $ per share, the shares of Series E preferred stock will convert into a larger number of shares of common stock; if the initial public offering price is equal to the midpoint of the range on the cover of this prospectus, the Series E preferred stock would convert into shares of common stock. A $1.00 decrease in the initial public offering price would increase by , and a $1.00 increase in the initial public offering price would decrease by , the number of shares of common stock issuable upon conversion of the Series E preferred stock.

You should read this table together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes included elsewhere in this prospectus.


	September 30, 2011
	Actual			Pro forma			Pro forma as adjusted
	(in thousands, except share and per share data)
Cash, cash equivalents	$	238,748		$	238,748		$

Current portion of long-term debt	$	24,675		$	24,675		$
Long-term debt, less current portion		20,000			20,000
Preferred stock warrant liability		2,574			—
Common stock warrant liability		—			2,574

Temporary equity:
Convertible Preferred Stock Series E, $0.0001 par value; 23,428,663 shares authorized, 23,092,864 shares issued and outstanding, actual; no shares authorized, no shares issued and outstanding, pro forma and pro forma as adjusted		196,737			—
Stockholders’ equity (Permanent Equity):
Convertible Preferred Stock, $0.0001 par value; 56,363,705 shares authorized, 56,043,080 shares issued and outstanding, actual; no shares authorized, issued and outstanding, pro forma and pro forma as adjusted		5
Preferred Stock, $0.0001 par value; no shares authorized, issued and outstanding, actual; shares authorized, no shares issued and outstanding, pro forma and pro forma as adjusted		—
Common Stock $0.0001 par value; 130,000,000 shares authorized, 15,208,394 issued and outstanding, actual; 130,000,000 shares authorized, pro forma and pro forma as adjusted; shares issued and outstanding, pro forma; shares issued and outstanding, pro forma as adjusted		1			8
Additional paid-in capital		340,031			536,766
Accumulated deficit		(280,959	)		(280,959	)

Total stockholders’ equity		59,078			255,815

Total capitalization	$	303,064		$	303,064		$

The number of shares of common stock set forth in the table above excludes:

10,811,355 shares issuable upon the exercise of options outstanding as of September 30, 2011 at a weighted average exercise price of $3.71 per share under our 2006 Stock Plan;

386,159 shares issuable upon exercise of warrants outstanding as of September 30, 2011 at a weighted average exercise price of $6.98 per share assuming certain financing conditions related to our term loan are met or 516,278 shares issuable upon exercise of warrants outstanding as of September 30, 2011 at a weighted average exercise price of $6.92 per share assuming such financing conditions are not met;

4,175,474 shares reserved for issuance upon exercise of options that may be granted subsequent to September 30, 2011 under our 2006 Stock Plan;

DILUTION

As of September 30, 2011, our net tangible book value was approximately $55.9 million or $3.67 per share of common stock, and our pro forma net tangible book value was $255.2 million or $2.70 per share of our common stock. Pro forma net tangible book value per share represents the amount of our total tangible assets reduced by the amount of our total tangible liabilities and convertible preferred stock divided by the total number of shares of common stock outstanding, pro forma after giving effect to the issuance of shares of common stock upon the conversion of all outstanding shares of our preferred stock effective immediately prior to the completion of this offering. After giving effect to the sale of the shares of common stock offered by us at an assumed initial public offering price of $ per share, and the adjustments set forth above, our pro forma as adjusted net tangible book value as of September 30, 2011 would have been $ or $ per share of common stock. This represents an immediate increase in pro forma as adjusted net tangible book value of $ per share to existing stockholders and an immediate dilution of $ per share to new investors.


Assumed initial public offering price per share		$
Pro forma net tangible book value per share before this offering	$
Increase attributable to new investors

Pro forma as adjusted net tangible book value per share after this offering

Dilution per share to new investors		$

If the underwriters exercise their option to purchase shares of common stock in full, the pro forma as adjusted net tangible book value per share after giving effect to this offering would be $ per share, and the dilution per share to investors in this offering would be $ per share.

The following table summarizes on a pro forma basis, as of September 30, 2011, the differences between the existing stockholders and new investors with respect to the number of shares of common stock purchased from us, the total consideration paid to us and the average price per share paid.


	Shares Purchased				Total Consideration				Average Price Per Share
	Number	Percent			Amount	Percent			Average Price Per Share
Existing stockholders				%	$			%	$
New investors

Totals			100.0	%	$		100.0	%

The number of shares purchased from us by existing stockholders, and the per share calculations derived from such number of shares, in this “Dilution” section are based on our common stock outstanding as of September 30, 2011, after giving effect to the conversion of all of our convertible preferred stock outstanding as of September 30, 2011 into common stock. The number of shares purchased from us by existing stockholders excludes:

10,811,355 shares issuable upon the exercise of options outstanding as of September 30, 2011 at a weighted average exercise price of $3.71 per share under our 2006 Stock Plan;

386,159 shares issuable upon exercise of warrants outstanding as of September 30, 2011 at a weighted average exercise price of $6.98 per share;

4,175,474 shares reserved for issuance upon exercise of options that may be granted subsequent to September 30, 2011 under our 2006 Stock Plan;

SELECTED CONSOLIDATED FINANCIAL DATA

The selected consolidated financial data set forth below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements, the notes thereto and the other information contained in this prospectus. The selected consolidated statements of operations data for the years ended December 31, 2008, 2009 and 2010 and the selected consolidated balance sheet data as of December 31, 2009 and 2010, have been derived from our audited consolidated financial statements that are included elsewhere in this prospectus. The consolidated statements of operations data for the years ended December 31, 2006 and 2007 and the balance sheet data as of December 31, 2006, 2007 and 2008, are derived from audited consolidated financial statements not included in this prospectus. The consolidated statements of operations data for the nine months ended September 30, 2010 and September 30, 2011 and balance sheet data as of September 30, 2011 are derived from our unaudited consolidated financial statements that are included elsewhere in this prospectus. The unaudited consolidated financial statements were prepared on a basis consistent with our audited consolidated financial statements and include, in the opinion of management, all adjustments necessary for the fair presentation of the financial information contained in those statements. The historical results presented below are not necessarily indicative of results to be expected for any subsequent period.


	Year Ended December 31,															Nine Months Ended September 30,
	2006(1)			2007			2008			2009			2010			2010			2011
	(in thousands, except share and per share data)
Consolidated Statements of Operations Data:
Revenues	$	550		$	4,362		$	7,082		$	11,573		$	13,494		$	11,468		$	71,203
Cost of revenues		550			4,072			17,214			19,014			31,457			22,456			80,762

Gross profit (loss)		—			290			(10,132	)		(7,441	)		(17,963	)		(10,988	)		(9,559	)

Operating expenses:
Research and development(2)		629			8,576			16,645			9,717			8,551			6,058			13,821
Project development(2)		147			3,862			8,397			12,392			18,226			12,267			19,597
Marketing, general and administrative(2)		747			5,040			10,619			14,331			24,367			16,918			28,922
Loss on deconsolidation of consolidated subsidiary		—			—			—			—			—			—			22,824

Loss from operations		(1,523	)		(17,188	)		(45,793	)		(43,881	)		(69,107	)		(46,231	)		(94,723	)
Interest income (expense), net		(12	)		1,031			1,673			(150	)		(1,949	)		(365	)		(7,861	)
Other income (expense), net		—			458			(488	)		268			(553	)		(500	)		(1,021	)

Loss before income taxes		(1,535	)		(15,699	)		(44,608	)		(43,763	)		(71,609	)		(47,096	)		(103,605	)
Provision for income taxes		—			8			10			17			22			18			83

Net loss	$	(1,535	)	$	(15,707	)	$	(44,618	)	$	(43,780	)	$	(71,631	)	$	(47,114	)	$	(103,688	)

Net loss per share of common stock, basic and diluted(3)	$	(0.15	)	$	(1.56	)	$	(4.42	)	$	(4.03	)	$	(4.93	)				$	(6.86	)

Shares used in computing net loss per share of common stock, basic and diluted(4)		10,563,118			10,100,204			10,084,167			10,853,073			14,527,834						15,115,786

Pro forma net loss per share of common stock, basic and diluted(5)													$	(1.12	)				$	(1.15	)

Weighted average shares used in computing the pro forma net loss per share of common stock, basic and diluted														63,684,677						90,282,311


	As of December 31,										As of September 30,
	2006		2007		2008		2009		2010		2011		Pro Forma⁽⁶⁾
Consolidated Balance Sheets Data:		(in thousands)
Cash and cash equivalents	$	8,437	$	26,236	$	102,513	$	18,780	$	37,785	$	238,748	$	238,748
Property, plant and equipment, net		190		593		2,182		6,471		14,479		26,767		26,767
Capitalized project costs		—		—		1,790		29,474		118,355		23,544		23,544
Working capital		8,274		26,065		78,989		2,930		7,929		17,012		18,531
Total assets		10,143		34,013		126,531		93,812		316,115		608,678		608,678
Preferred stock warrant liability		—		—		—		—		840		2,574		2,574
Long-term liabilities, less current portion		305		346		186		4,194		11,905		30,667		29,612
Temporary equity: Convertible Preferred Stock Series E		—		—		—		—		27,071		196,737		—
Total stockholders’ equity	$	8,837	$	29,742	$	100,607	$	58,716	$	158,803	$	59,078	$	255,815

(1)	We commenced operations on May 1, 2006.

(2)	Includes share-based compensation expense as follows:


	Year Ended December 31,										Nine Months Ended September 30,
	2006		2007		2008		2009		2010		2010		2011
	(in thousands)
Research and development	$	—	$	49	$	120	$	218	$	264	$	193	$	577
Project development		—		46		273		374		675		465		863
Marketing, general and administrative		—		298		575		816		1,398		792		2,197

Total	$	—	$	393	$	968	$	1,408	$	2,337	$	1,450	$	3,637

(3)

Our basic net loss per share of common stock is calculated by dividing the net loss by the weighted-average number of shares of common stock outstanding for the period. The diluted net loss per share of common stock is computed by dividing the net loss by the weighted-average number of shares of common stock, excluding common stock subject to repurchase, and, if dilutive, potential shares of common stock outstanding during the period. Potential shares of common stock consist of stock options to purchase shares of our common stock and warrants to purchase shares of our convertible preferred stock (using the treasury stock method) and the conversion of our convertible preferred stock (using the if-converted method). For purposes of these calculations, potential shares of common stock have been excluded from the calculation of diluted net loss per share of common stock as their effect is anti-dilutive since we generated a net loss in each period.

(4)

The basic and diluted net loss per share computation excludes potential shares of common stock issuable upon conversion of convertible preferred stock and exercise of options and warrants to purchase common stock as their effect would be anti-dilutive. See note 18 to our consolidated financial statements for a detailed explanation of the determination of the shares used in computing basic and diluted loss per share.

(5)	Pro forma basic and diluted net loss per share of common stock has been computed to give effect to (i) the conversion of the convertible preferred stock into common stock and (ii) the exercise of warrants to purchase 60,387 shares of Series A preferred stock in December 2011.

(6)

On a pro forma basis to reflect the conversion on a one-for-one basis of all of our convertible preferred stock outstanding as of September 30, 2011 into common stock. The number of shares of our common stock to be issued upon conversion of our outstanding shares of Series E preferred stock depends in part on the initial offering price of our common stock in this offering. See “Summary—The Offering.”

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

The following discussion of our financial condition and results of operations should be read together with the consolidated financial statements and related notes that are included elsewhere in this prospectus. This discussion may contain forward-looking statements based upon current expectations that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of various factors, including those set forth under “Risk Factors” or in other parts of this prospectus. The following discussion reflects the effects of the restatement of the consolidated statement of cash flows discussed in note 19 to our consolidated financial statements.

Overview

We are a leading solar thermal technology company that designs, develops and sells proprietary systems that produce reliable, clean energy in utility-scale electric power plants. Our systems use proprietary solar power tower technology to deliver cost-competitive renewable electricity and high-temperature steam for use in applications such as thermal enhanced oil recovery, or EOR. In implementing systems using our proprietary technology, we partner with several parties to develop utility-scale solar electric power plants. These parties include engineering, procurement and construction, or EPC, contractors; boiler suppliers; turbine suppliers; and financing parties that may consist of strategic and/or financial investors.

While we primarily sell systems using our proprietary technology, we also act as the system architect for the layout and optimization of the solar field. In addition, we provide technical services related to the design, engineering and operation of our systems and may provide overall project development services. During the construction phase of a project, we may recognize revenue from the sale of our proprietary technology. For the projects where we lead development, we expect to own initially 100% of the equity in the projects, but may seek development partners on specific projects. A project’s assets are typically held by a special purpose, single member limited liability company, in which we are initially the sole member, that we refer to as a project company. We intend to ultimately transfer the majority of the equity in these project companies to third parties while retaining a minority equity interest, as we did with Ivanpah. Until the time of such transfer, we expect to wholly own each project company and consolidate its profits and losses in our financial statements. Outside of the United States, we may or may not have ownership interests in such projects using our systems.

Through our project companies, we have 13 executed and outstanding power purchase agreements, or PPAs, to deliver approximately 2.4 GW of installed capacity to two of the largest electric utilities in the United States, Pacific Gas and Electric Company, or PG&E, and Southern California Edison, or SCE. We believe these PPAs represent one of the largest utility-scale solar pipelines in the United States and should provide us with a significant revenue opportunity between 2013 and 2016. For purposes of illustration, our agreements for the supply of equipment and services to the Ivanpah project, which has three PPAs totaling 377 MW, represent $672.0 million of contracted sales, which equates to approximately $1.8 million of contracted sales per MW. Consistent with our 14% ownership in Ivanpah, we will recognize 86% of any actual sales as revenue.

From our inception through September 30, 2011, we have recognized $108.3 million in revenue. As of September 30, 2011, we had an accumulated deficit of $281.0 million. We experienced net

losses of $44.6 million for the year ended December 31, 2008, $43.8 million for the year ended December 31, 2009, $71.6 million for the year ended December 31, 2010 and $103.7 million for the nine months ended September 30, 2011.

Opportunities, Challenges and Risks

Globally, the solar industry has experienced significant growth in recent years. There has been increased demand for solar energy as costs for electricity generated from solar resources have become more competitive relative to fossil fuel generation and as a result of government incentives and mandates, such as state renewable portfolio standards, or RPS, in the United States. We expect the increasing demand for energy generated from solar and other renewable resources and changes in government regulation to be the most significant trends affecting our industry today and in the immediate future.

Although other opportunities, challenges and risks 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 several key opportunities, challenges and risks. These include our pipeline execution and business development, financing requirements and governmental programs and incentives, as described below.

Our Pipeline Execution and Business Development

We expect to generate the majority of our revenues from sales of our systems to utility-scale solar thermal power plants. The economic feasibility of these plants is materially affected by electricity market prices. PPAs are contracts that provide for the purchase of electricity at an agreed-upon price for a specified period of time. Long-term PPAs, which may be as long as 20 to 25 years for solar projects, provide a predictable revenue stream and significantly limit the impact of market price variability. We believe this type of PPA substantially enhances the ability to obtain long-term, non-recourse financing which is generally considered critical for solar projects such as ours.

Through our project companies, we have 13 executed and outstanding PPAs with PG&E and SCE to deliver approximately 2.4 GW of installed capacity. We attempt to match each signed PPA with a site in our development portfolio that is consistent with and fulfills the requirements of the PPA. Depending on the size of a given site, multiple PPAs can be associated with it. For example, three of the PPAs we signed are associated with Ivanpah, and we retain 10 PPAs to deliver approximately 2.0 GW of installed capacity. In addition, we are actively working to secure additional PPAs, which we intend to match with sites in our portfolio. As part of meeting our obligations under these 10 PPAs and the additional PPAs we are pursuing, we have a robust development site portfolio currently comprised of approximately 90,000 acres of land under our control across California and the U.S. Southwest. This site portfolio has the potential to accommodate approximately 9 GW (gross) of installed capacity.

We dedicate resources to the development of each site based on the likely date by which we expect deliveries of electricity from the site to commence. Our site portfolio is frequently reviewed and could change. New sites are identified and added to the portfolio, and existing sites are re-prioritized or removed from the portfolio. The attractiveness of a particular site, and its priority of importance within our site portfolio, is driven by such things as the quality of the solar insolation at the site, availability of transmission, environmental considerations, the predicted ease of permitting the site, the size of the site, the likelihood of fatal flaws at the site, the cost of maintaining control of the site, and the probable schedule for development of the site as compared to others in the site portfolio. The cost of developing a site varies substantially, depending on such things as whether it is publicly- or privately-owned land, whether it is has previously been used for agricultural or other purposes, environmental considerations, the density of plants and animals and, in particular, the presence of endangered or threatened species on the site, and other factors that influence the permitting process.

We defer linkage of specific sites with specific PPAs, until the sites are in advanced development as described below, because we are constantly prospecting for better sites than those in our portfolio. The PPAs are generally not site specific and will be assigned to a particular site based on various considerations. We believe that the sites in our portfolio will allow us to develop projects sufficient to meet our obligations under our PPAs.

Sites which meet our specific project viability criteria are considered in “advanced development.” Once a site is in advanced development, its budget includes site acquisition costs, permitting, environmental compliance, transmission interconnection costs, preparation of project contracts, and early engineering work. The advanced development budget for any site typically is in excess of $20 million and is expected to be funded through cash balances and the net proceeds of this offering.

Risk is inherent in project development, but we follow a careful process of constant review and evaluation that manages and mitigates risks to the extent possible. Our long-term business plan and budget include appropriate funding to support development activities across our site portfolio, in order to meet our obligations under our existing PPAs and support additional opportunities. We could incur significant expenditures on a given site with which we later do not proceed.

We currently have three sites in advanced development, Rio Mesa Solar and Hidden Hills Ranch, each located in California, and Sandy Valley, located in Nevada. Rio Mesa Solar consists of approximately 5,800 acres and in October 2011, we filed an Application for Certification with the California Energy Commission (CEC) for the development of three 250 MW solar power plants. Hidden Hills Ranch consists of approximately 3,300 acres and in August 2011, we filed a similar application with the CEC for the development of two 250 MW solar power plants. Sandy Valley consists of approximately 10,000 acres.

Ivanpah, the first project that will deliver power to serve PPAs that we have signed, is comprised of three concentrating solar thermal power plants. This project is located on an approximately 3,500 acre site in California’s Mojave Desert and will have an installed capacity of 377 MW. Construction of Ivanpah began in October 2010 and operations for all three phases are scheduled to commence in 2013. All three Ivanpah phases have fully-committed equity and debt financing to fund construction costs, together with other project costs such as interest during construction, sales tax, mitigation and development costs, interconnection costs, cost contingencies and debt reserves.

In addition to executing on our existing pipeline of PPAs, we are focused on identifying additional opportunities to sell our systems in targeted international and domestic markets. We are partnering with Alstom on bids for projects in international markets, such as the Middle East, Northern Africa, South Africa, Southern Europe and India. For example, in March 2011, we jointly submitted a bid with Alstom in response to a tender process conducted by the State of Israel for a 110 MW solar thermal power plant near Ashalim, Israel. In September 2011, the tender committee advised us that the bid has passed the minimum threshold requirements but has been provisionally rejected due to the pricing. The committee has indicated that it expects to invite us to meet with it to discuss certain issues relating to the bid. We also intend to pursue additional opportunities for the development of large scale thermal EOR projects using our systems globally. Our Coalinga Solar-to-Steam for EOR project in California, developed in partnership with Chevron, represents our first thermal EOR project and commenced operations in October 2011. We believe that solar-to-steam applications of our systems, such as thermal EOR, represent a significant growth opportunity.

Financing Requirements

Development and construction of large scale solar thermal facilities is capital intensive. As a result, the ability to access capital efficiently and effectively is crucial to our growth strategy. For example, Ivanpah received a $1.6 billion loan, guaranteed by the U.S. Department of Energy, or DOE,

and funded by the Federal Financing Bank, a branch of the U.S. Department of Treasury, or U.S. Treasury. In addition, Ivanpah has received a total equity commitment of $598 million, consisting of $300 million from NRG Solar, $168 million from a Google Inc. affiliate and $130 million from us. While Ivanpah has fully committed financing, executing on our pipeline and expanding our business requires significant additional capital. Once Ivanpah and the Coalinga Solar-to-Steam for EOR project are operational, we expect to be able to access the traditional project finance and capital markets to both develop and construct future projects.

Governmental Programs and Incentives

U.S. Renewable Portfolio Standards: Among the more significant factors driving growth in our business in the United States are state-mandated RPS. We expect to continue to benefit from the increasing demand for renewable energy as a result of favorable legislation adopted by over half of the states, including our initial target markets in California and the U.S. Southwest. In each of these states, relevant legislation currently requires 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 our business.

U.S. Federal Tax and Economic Incentives: We utilize U.S. federal government programs supporting renewable energy, which enhance the economic feasibility of developing our projects. The key federal programs include ITCs, cash grants in lieu of ITCs and loan guarantees under the ARRA, and accelerated depreciation of renewable energy property. In April 2011, we closed the $1.6 billion construction and term loan facility guaranteed by the DOE to help finance construction of Ivanpah. Ivanpah also qualifies for cash grants in lieu of ITCs in the aggregate amount of approximately $570 million, which are expected to be paid within 60 days after each project is placed in service. We may apply for additional federal loan guarantees and cash grants for future projects if they remain available; however, our financing strategy for future projects does not contemplate the use of federal loan guarantees or cash grants.

International Government Incentives: Outside of the United States, we expect that a variety of governmental initiatives and the adoption of programs designed to encourage clean renewable and sustainable energy sources at the national, provincial and local levels will create new opportunities for the development of new solar projects.

Basis of Presentation

The following describes certain line items in our consolidated statements of operations:

Revenues

We primarily sell systems using our technology to utility-scale solar thermal power projects or to oil and gas production companies pursuing thermal EOR activities. We also generate revenue from technical services provided to the long-term owners of projects using our systems. In addition to selling systems to project companies, we also expect to generate revenue through system sales to and licensing arrangements with development partners, particularly in key markets outside of the United States.

We generally recognize revenue over the development and construction periods of the projects to which we sell, which typically extend over multiple years, using the percentage-of-completion method of accounting. Under this method, estimated contract revenue is accrued based on the percentage that costs to date bear to total estimated costs. Anticipated contract losses are estimated and recognized in full in the period in which the loss becomes evident. Contract revenue and total cost estimates are

reviewed at least quarterly and revised periodically as the work progresses and adjustments to estimated contract revenue and total cost estimates are reflected in the period when such estimates are revised. These estimates require significant management judgment because the underlying assumptions are subject to change as the projects progress and better information becomes available. Actual results may vary substantially from management’s estimates.

Revenues may be deferred, either in part or in whole, dependent on our ability to estimate costs, which may be impacted by our post-delivery obligations or guarantees such as installation, customer acceptance or performance guarantees. Our continued investment and other potential forms of continuing involvement in these projects may restrict the amounts that we are able to recognize as revenue.

Our sales are typically to project companies that have been formed to facilitate our project development and construction activities. Depending upon our ownership interest, degree of control and influence over the project companies, we may consolidate these entities, and therefore will not recognize any revenue associated with the sales of our systems or services. For those project companies that are not consolidated, we will recognize revenues associated with the sales of our systems and provision of services, subject to our continuing ownership percentages. For example, if we retain a 10% ownership interest in a project company, we will generally only recognize 90% of the profit from our sales to that project company. See our discussion of critical accounting policies below and in note 2 to our consolidated financial statements for additional information regarding our policies for consolidation and deconsolidation of project companies.

We anticipate that we will transfer ownership interests in the project companies, accept additional investors, contribute the assets of the project companies to a joint venture or otherwise experience a change in the degree of control we are able to exercise. When this occurs, we must evaluate the facts and circumstances of each project to determine whether we should continue to consolidate the operations of the project companies. When appropriate, we will deconsolidate a project company that had been previously consolidated and will only then recognize revenue from sales to that entity, subject to the conditions discussed above. Revenue from our sales to an unconsolidated project company may be limited by our continued investment in that entity, and so revenues that are recognized in our financial statements may be less than the total sales to these project companies.

The transfers of our interests in project companies, sale of equity interests or contributions to joint ventures, in which we will have typically gained control of land or land rights, are evaluated based on the stage of development of the project and the composition of the assets within the project prior to sale or contribution. We evaluate the composition and fair value of assets sold or contributed within the project companies at the date of the transaction to determine whether a significant amount of the fair value is real estate or non-real estate assets. If the stage of development or fair value of the underlying assets results in the determination that the underlying assets are real estate in nature, we will carry the full value of the asset under construction on our books and would not record revenue until such time as the project was delivered and the earnings process complete. Transfers of project interests or contributions to joint ventures are generally not deemed revenue, with gains or losses from these transactions normally recorded in “Loss on deconsolidation of consolidated subsidiary” in our consolidated statements of operations. See “—Critical Accounting Policies and Estimates” for further information regarding our consolidation and revenue recognition policies.

Through September 30, 2011, our revenues have been primarily associated with two projects, Ivanpah and the Coalinga Solar-to-Steam for EOR project.

Ivanpah: Prior to April 2011, substantially all of our revenue associated with Ivanpah was derived from sales of development services to Solar Partners II, LLC, or SPII, one of the project companies formed to facilitate the development of Ivanpah. From March 2007 to October 2009, we were an investor in this project company but did not consolidate the entity as we were not

considered the primary beneficiary. Therefore, revenue relating to services provided to this entity was recognized as the services were delivered through October 2009. After October 2009, as a result of our acquisition of additional interests in SPII, this entity was consolidated and all subsequent activity, which had previously been reported as revenue, was eliminated in consolidation. Beginning in the fourth quarter of 2010, construction of Ivanpah commenced. In April 2011, we contributed all of the project companies associated with Ivanpah, including SPII to a new entity, Ivanpah Master Holdings, LLC, or Ivanpah HoldCo, contributed additional assets and accepted new investors into that entity to complete the financing for the Ivanpah project. Following the investment by third-party investors, we are no longer the primary beneficiary of Ivanpah HoldCo or the Ivanpah project companies and, accordingly, have deconsolidated Ivanpah HoldCo.

All revenue from the Ivanpah project subsequent to October 2009 has been associated with our fixed-price solar field supply and related services contracts. We recognize revenue on these contracts using the percentage-of-completion method of accounting. Consistent with our 14% ownership interest in the Ivanpah project, we will recognize 86% of the profit margin with respect to our sales to the project only at the time that we are able to make reasonable estimates.

Coalinga Solar-to-Steam for EOR project: All revenue from the Coalinga Solar-to-Steam for EOR project located in Coalinga, California has been associated with solar field supply sales and services. The current contract value including change orders is $27.8 million, of which nearly 100% has been recognized through September 30, 2011. We have recognized revenue on this contract using the percentage-of-completion method of accounting, with revenue measured as the percentage of cost incurred to date to the total estimated costs to complete the contract. Start-up and commissioning occurred in October 2011. This fixed price contract for the Coalinga Solar-to-Steam for EOR project was entered into at a loss. We entered into this loss contract for the purposes of providing a commercially scaled demonstration of our technologies, establishing our technology as a viable solution for the enhanced oil recovery market, validating our heliostat manufacturing processes at volume, testing our supply chain and logistics, and isolating any previously unidentified design or other issues inherent in the construction of a solar field.

In December 2008, upon execution of the commercial agreement to construct the Coalinga Solar-to-Steam for EOR project, we recognized a provision for estimated contract losses representing $10.5 million. At that time, the estimate of the contract loss was considered reliable and, as such, the appropriate revenue recognition was deemed to be the percentage-of-completion method. As of September 30, 2011, we have recognized a cumulative provision for loss representing the entire anticipated loss since inception of $61.0 million, or $50.5 million greater than the initial loss estimate as recognized in December 2008. Discrete events transpired during the periods subsequent to when the initial loss estimate was made, through September 30, 2011, that required adjustments to the original estimated costs to complete the project. These items included non-recoverable customer driven design changes, increased vendor and material costs due to scope and design changes, increased mechanical and electrical costs associated with design and engineering changes, delays and subsequent costs to remobilize and accelerate construction as the result of abnormal weather patterns, and increased costs associated with efforts to accelerate the scheduled completion of the facility.

During the first half of 2011, we experienced substantial increases in our estimated cost to complete due to additional costs being identified that were primarily associated with design specification errors provided by one of our third-party design engineering subcontractors. As we neared the final stages of the construction process, we identified design issues that led to our replacing this design engineering subcontractor. A subsequent detailed review resulted in modification of certain engineering designs associated with the solar tower systems. This change resulted in significant delay and substantial rework. This also resulted in our other

construction and electrical subcontractors incurring substantial cost which we do not anticipate being able to recover. The project began operations in October 2011; however, until final acceptance of the project is received, our costs may increase and accordingly, we may incur additional provisions for losses.

We do not intend to act as EPC contractor on Ivanpah or future projects as construction and construction management are not our core competencies. Highly skilled and competent EPC contractors, which possess the necessary expertise to effectively fulfill the EPC function, are available and are better qualified to execute the EPC function. For example, Bechtel is acting as the EPC contractor for Ivanpah under a fixed-price contract with our role limited to supplying our proprietary solar field materials and technology and providing engineering and other technical services. We believe that this approach reduces the potential for cost overruns, making our projects more attractive to investors, as the EPC contractor will have sole responsibility for cost overruns with respect to the EPC function. We also believe this approach will facilitate making our liquidity and capital resources needs more predictable.

Cost of Revenues and Gross Profit (Loss)

Cost of revenues includes cost of materials, labor costs, overhead, amortized tooling costs, shipping and logistics costs, engineering support, testing, and reserves for estimated warranty costs and reserves for performance guarantees. Cost of revenues vary significantly between periods depending on the level of billable development activity and changes in our percentage of ownership in a particular project. The applicable Ivanpah project contracts and the Coalinga Solar-to-Steam for EOR project contract are accounted for under construction accounting. If the estimated total costs to complete our scope of supply under a construction accounting contract are in excess of the contract value, the contract is considered a “loss contract”, as is the case for the Coalinga Solar-to-Steam for EOR project. As a loss contract, any changes in the underlying estimates which increase the expected loss are recognized in the period in which the change becomes evident.

We anticipate a significant increase in engineering, procurement, quality assurance and other costs associated with our cost of revenue as we source and deliver our solar technologies and services into Ivanpah and future projects.

We define our gross profit (loss) as our total revenues less our total cost of revenues, and our gross margin as our gross profit (loss) expressed as a percentage of total revenue.

Operating Expenses

Our operating expenses include research and development, project development, marketing, general and administrative, and loss on deconsolidation of consolidated subsidiary expenses. Operating expenses are subject to substantial fluctuation between periods depending on the status of projects under development. As projects meet our criteria for project capitalization, project development costs that were expensed in prior periods will be prospectively capitalized, and our operating expenses in such future periods will be reduced by the amount of the costs that we capitalize. Costs which were expensed in preceding periods are not capitalized. The criteria for project capitalization include control of the underlying properties, a determination that the site can be developed as planned and the linking of an off-take agreement, such as a PPA, to a site or other viable economic justification for constructing the project. Upon achieving these milestones, we capitalize on a prospective basis all costs of design, development, construction and other costs directly associated with the development of the projects. We do not typically capitalize research and development or marketing, general and administrative costs; however, costs that are directly linked to development of the project, such as legal and regulatory costs associated with the project or personnel assigned to

support project specific development activities, may be capitalized if deemed eligible. If it should be determined that a project is no longer viable, any costs that had been previously capitalized would be immediately expensed in the period the determination is made.

Research and Development

Research and development expenses consist primarily of personnel costs for our teams in engineering and research, prototyping expense, contract and professional services, and amortized equipment expense. Research and development expenses also include the costs of operating our Solar Energy Development Center, or SEDC, in Israel. We expense research and development costs as incurred.

We consider continued research and development key to our business and devote considerable effort and resources to enhance the efficiency, reliability and capacity factor of our solar thermal technology to maintain our competitive advantage over alternative technologies. Subsequent to the completion of our SEDC facility and the transition of Ivanpah from a development activity into design and construction, our expenditures in research and development have decreased significantly. However, we anticipate that research and development expenses will increase in terms of dollar amounts and will decline as a percentage of revenue.

Project Development

Project development expenses consist primarily of land options, land leases, transmission access and integration costs, project engineering, third-party engineering studies, environmental costs, legal, regulatory, and consulting fees, and other direct costs associated with identification and development of suitable sites for our solar thermal power facilities. Also included are personnel costs for our teams in site acquisition, transmission, environmental, regulatory and project engineering. We expense all costs associated with our project development activities until such time as we achieve our project viability criteria. If a project is abandoned or deemed to be no longer viable, all capitalized costs are expensed in the period the abandonment occurs. Depending upon the timing of when a project becomes subject to capitalization, or if a project previously subject to capitalization is abandoned, there may be significant differences in project development expense between periods.

We consider our project development activities integral to our effort to grow the market for our technologies and will continue to expend significant effort and expense to grow our portfolio of projects. We expect that project development will increase in terms of dollar amounts but will decline as a percentage of revenue as a result of increased product sales.

Marketing, General and Administrative

Marketing, general and administrative expenses consist primarily of personnel and facilities costs related to our marketing, executive, finance, human resources, information technology and legal functions, as well as fees for professional and contract services. We expense marketing, general and administrative costs as incurred.

As our business has grown, we have increased our expenditures on marketing, general and administrative functions necessary to support this growth. Following the offering, we will incur additional marketing, general and administrative expenses related to operating as a public company, such as increased legal and accounting expenses, the cost of an investor relations function, costs related to compliance with Section 404 of the Sarbanes-Oxley Act of 2002 and increased director and officer insurance premiums. We expect marketing, general and administrative services will continue to increase in terms of dollar amounts but will decline as a percentage of revenue as we continue to grow and expand our operations, increase our marketing team to handle our expanding business activity, expand into international markets and transition to becoming a public company.

Loss on Deconsolidation of Consolidated Subsidiary

Loss on deconsolidation of consolidated subsidiary represents the difference between the value of assets received, at fair value, the fair value of any retained interest, and the historic cost of the assets deconsolidated. In cases where we transfer control of the entity but retain an investment in the entity, we will generally recognize any resulting gain or loss from deconsolidation as an operating expense.

Interest Income (Expense), Net

Interest income (expense), net consists of interest earned on cash balances and short-term investments less interest paid on outstanding borrowings. We have historically invested our available cash balances in money market funds, short-term U.S. Treasury obligations and commercial paper. We expect interest expense to increase in absolute dollars as we expand our operations to the extent we utilize debt financing to fund this expansion. We anticipate that interest associated with the financing of construction on projects in which we are an investor will not be reflected in our financial statements as interest expense but rather will be capitalized to the project companies to the extent they qualify.

Other Income (Expense), Net

Other income (expense), net consists primarily of transaction gains and losses on our foreign currency-denominated assets and liabilities and the change in the fair value of our convertible preferred stock warrant liability. Our primary foreign currencies are the euro and the Israeli shekel. We expect our transaction gains and losses will vary depending upon movements in the underlying exchange rates.

Provision for Income Taxes

Income taxes are computed using the assets and liability method, under which deferred tax assets and liabilities are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to affect taxable income. Valuation allowances are established when necessary to reduce deferred tax assets to the amount expected to be realized.

We believe, based on the available information, it is more likely than not that our deferred tax assets will not be realized, and, accordingly, we have taken a full valuation allowance against all of our United States and Israeli deferred tax assets. As of December 31, 2010, we had approximately $89.7 million of federal, $86.1 million of California and $52.8 million of foreign operating loss carry-forwards available to offset future taxable income, which expire in varying amounts beginning in 2027 for federal, 2017 for state if unused, but do not expire for international purposes.

Federal and state laws impose substantial restrictions on the utilization of net operating loss and tax credit carry-forward in the event of an “ownership change,” as defined in Section 382 of the Code. Our existing net operating losses and tax credits may be subject to limitations arising from previous ownership changes, and if we undergo an ownership change in connection with or after this offering, our ability to utilize NOLs and tax credits could be further limited by Section 382 of the Code. Future changes in our stock ownership, some of which are beyond our control, could result in an ownership change under Section 382 of the Code. Furthermore, our ability to utilize NOLs of any companies that we may acquire in the future may be subject to limitations. For these reason, we may not be able to utilize a material portion of the NOLs or tax credits reflected on our balance sheet, even if we attain profitability.

Results of Operations

The following table sets forth our historical operating results as of the periods indicated:


	Year Ended December 31,									Nine Months Ended September 30,
	2008			2009			2010			2010			2011
	(in thousands)
Consolidated Statements of Operations Data:
Revenues	$	7,082		$	11,573		$	13,494		$	11,468		$	71,203
Cost of revenues		17,214			19,014			31,457			22,456			80,762

Gross loss		(10,132	)		(7,441	)		(17,963	)		(10,988	)		(9,559	)
Operating expenses:
Research and development		16,645			9,717			8,551			6,058			13,821
Project development		8,397			12,392			18,226			12,267			19,597
Marketing, general and administrative		10,619			14,331			24,367			16,918			28,922
Loss on deconsolidation of consolidated subsidiary		—			—			—			—			22,824

Loss from operations		(45,793	)		(43,881	)		(69,107	)		(46,231	)		(94,723	)
Interest income (expense), net		1,673			(150	)		(1,949	)		(365	)		(7,861	)
Other income (expense), net		(488	)		268			(553	)		(500	)		(1,021	)

Loss before income taxes		(44,608	)		(43,763	)		(71,609	)		(47,096	)		(103,605	)
Provision for income taxes		10			17			22			18			83

Net loss	$	(44,618	)	$	(43,780	)	$	(71,631	)	$	(47,114	)	$	(103,688	)

Comparison of the Nine Months Ended September 30, 2010 and 2011

Revenue

Revenues increased $59.7 million, or 519%, from $11.5 million for the nine months ended September 30, 2010 to $71.2 million for the nine months ended September 30, 2011. The increase was primarily due to a $66.8 million increase in revenues associated with the Ivanpah solar field supply and services contracts beginning in April 2011 with no comparable contracts in the previous year. Prior to April 5, 2011, we were the sole owner of the Ivanpah project and, as such, intercompany sales were eliminated. We recognize approximately 86% of the revenues generated from the supply and service contracts to Ivanpah HoldCo subsequent to the Ivanpah transaction closing in April 2011 using the percentage-of-completion method. We will continue to recognize approximately 86% of the revenues associated with the supply and services contracts to Ivanpah HoldCo until such time as our ownership interest changes or the project is complete, which is currently anticipated to be in 2013. Under the percentage-of-completion method, increases in the estimated cost to complete the project may have an adverse impact on revenue recognition for that period. This increase was partially offset by a $7.1 million decrease in revenues from the Coalinga Solar-to-Steam for EOR project. The decrease in revenues from the prior year was primarily driven by the decrease in construction related activities for the project as it neared completion. We turned over operations of the Coalinga Solar-to-Steam for EOR project to Chevron in October 2011. As a result, we do not expect future revenues relating to the construction of the Coalinga Solar-to-Steam for EOR project.

Cost of Revenues and Gross Loss

Cost of revenues increased $58.3 million, or 259%, from $22.5 million for the nine months ended September 30, 2010 to $80.8 million for the nine months ended September 30, 2011. The increase

was primarily due to a $50.3 million increase in cost of revenues for the Ivanpah solar field supply and services contracts and a $13.9 million increase in our estimated cost to complete the ongoing Coalinga Solar-to-Steam for EOR project, offset by a $5.9 million decrease in cost of revenues primarily driven by a decrease in construction activity as compared to the same nine-month period in 2010. The estimated cost increase in the Coalinga Solar-to-Steam for EOR project for the nine months ended September 30, 2011 was primarily due to changes in design associated with a change in the project engineering firm and redesign of certain elements of the tower design. As a result of the redesign, we experienced a number of unanticipated engineering change orders during the second quarter which resulted in substantial costs associated with the removal, rework and replacement of previously installed structures and equipment, as well as associated premium time to maintain the construction schedule. In October 2011, the Coalinga Solar-to-Steam for EOR project commenced operations.

Gross loss decreased from $11.0 million for the nine months ended September 30, 2010 to $9.6 million for the nine months ended September 30, 2011. Gross margins were (96)% for the nine months ended September 30, 2010 and (13)% for the nine months ended September 30, 2011. Gross loss decreased and gross margins increased primarily due to the increase in the revenues related to the Ivanpah solar field supply and services contracts.

Research and Development

Research and development costs increased $7.8 million, or 128%, from $6.0 million for the nine months ended September 30, 2010 to $13.8 million for the nine months ended September 30, 2011 due primarily to an increase in salaries and related expenses of $4.6 million, from $5.5 million for the nine months ended September 30, 2010 to $10.1 million for the nine months ended September 30, 2011. Allocations to projects and cost of revenues increased $1.2 million, from $2.9 million for the nine months ended September 30, 2010 to $4.1 million for the nine months ended September 30, 2011. Headcount associated with research and development activities increased to 149 at September 30, 2011, from 121 at September 30, 2010.

Project Development

Project development costs increased $7.3 million, or 60%, from $12.3 million for the nine months ended September 30, 2010 to $19.6 million for the nine months ended September 30, 2011 due primarily to an increase in direct and indirect costs of project development of $10.0 million and increased salaries and related expense of $4.0 million. These increases were partially offset by an increase in allocations to capitalized project costs for Hidden Hills Ranch and Rio Mesa Solar, in the amount of $6.9 million and a decrease of $0.5 million in consulting fees and professional services.

Marketing, General and Administrative

Marketing, general and administrative costs increased $12.0 million, or 71%, from $16.9 million for the nine months ended September 30, 2010 to $28.9 million for the nine months ended September 30, 2011 due to increased legal and consulting fees of $8.5 million primarily related to our Ivanpah financing, increased compensation related expense of $7.1 million and increased other administrative costs of $4.2 million. These increases were partially offset by an increase of $5.0 million in capitalized project costs to $9.8 million for the nine months ended September 30, 2011, from $4.8 million for the nine months ended September 30, 2010. Headcount associated with marketing, general and administrative increased to 120 at September 30, 2011, from 91 at September 30, 2010.

Loss on Deconsolidation of Consolidated Subsidiary

Loss on deconsolidation of consolidated subsidiary costs increased from nil for the nine months ended September 30, 2010 to $22.8 million for the nine months ended September 30, 2011 due to the

Ivanpah transaction. In April 2011, we contributed the Ivanpah Group and $30.5 million of additional assets to a newly formed holding company, Ivanpah HoldCo. Two additional investors contributed $416.0 million in return for an economic interest in Ivanpah HoldCo of 86%. This contribution was in the form of $116.8 million in cash and future commitments to fund an additional $299.2 million. As a result of this transaction, the assets of the Ivanpah Group were deconsolidated from our balance sheet, and we realized a loss of $77.7 million from the divestiture of an 86% economic interest in the Ivanpah HoldCo net assets. This loss was partially offset by a gain of $54.9 million related to the increase in fair value of the 14% retained noncontrolling economic interest in Ivanpah HoldCo as a result of the deconsolidation. For further information on this transaction, see note 7 to our consolidated financial statements.

Interest Income (Expense), Net

Interest expense, net increased $7.5 million from $0.4 million for the nine months ended September 30, 2010 to $7.9 million for the nine months ended September 30, 2011. The increase primarily related to interest and amortization of loan charges on our $75.0 million credit facility entered into in October 2010 and repaid in April 2011, and interest related to the Hercules term loan entered into in December 2010, of which we drew an additional $16.7 million in January 2011 for a total outstanding principal amount as of September 30, 2011 of $25.0 million, and the $20.0 million loan entered into with BDC Ivanpah, LLC, or BDC Ivanpah, in April 2011. BDC Ivanpah is controlled by the Bechtel Group, Inc.

Other Income (Expense), Net

Other expense, net increased $0.5 million from $0.5 million for the nine months ended September 30, 2010 to $1.0 million for the nine months ended September 30, 2011 due primarily to a $0.5 million loss from the change in fair value of the preferred stock warrants.

Comparison of the Years Ended December 31, 2008, 2009 and 2010

Revenue

Revenues increased $1.9 million, or 17%, from $11.6 million in 2009 to $13.5 million in 2010. The increase was due to increased construction revenues of $5.3 million related to the development of the Coalinga Solar-to-Steam for EOR project, offset by a decrease in services revenues of $3.4 million in 2010 as a result of our consolidation of Solar Partners II, the project company for the first phase of Ivanpah. Revenues associated with Solar Partners II was eliminated in our consolidated financial statements.

Revenues increased $4.5 million, or 63%, from $7.1 million in 2008 to $11.6 million in 2009. The increase was due to an increase of $6.9 million in construction revenues related to the Coalinga Solar-to-Steam for EOR project, offset by a $2.4 million decrease in project services revenues primarily caused by the consolidation of Solar Partners II.

Cost of Revenues and Gross Loss

Cost of revenues increased $12.5 million, or 65%, from $19.0 million in 2009 to $31.5 million in 2010. The increase was due in part to $5.3 million of additional costs for equipment, materials, engineering and other construction related costs and $10.4 million in increases in our estimated costs to complete our ongoing Coalinga Solar-to-Steam for EOR project, which was partially offset by a $3.4 million reduction in costs caused by the Ivanpah Reconsolidation. Gross loss increased from $7.4 million in 2009 to $18.0 million in 2010. Gross margins were (133)% in 2010 and (64)% in 2009. Gross loss and gross margins declined due to a greater increase in costs than in revenues associated with

the development of the Coalinga Solar-to-Steam for EOR project. We do not anticipate entering into another loss contract similar to the Chevron agreement, and therefore expect future gross margins to increase.

Cost of revenues increased $1.8 million, or 10%, from $17.2 million in 2008 to $19.0 million in 2009. The increase was due to $6.9 million in construction related costs associated with the commencement of construction of the Coalinga Solar-to-Steam for EOR project, offset by a reduction of $5.1 million of costs caused by the Ivanpah Reconsolidation. Gross loss declined from $10.1 million in 2008 to $7.4 million in 2009. Gross margins were (64)% and (143)% for the years ended December 31, 2009 and 2008, respectively. Gross loss declined due to increased revenues relating to the Coalinga Solar-to-Steam for EOR project.

Research and Development

Research and development costs decreased $1.1 million, or 12%, from $9.7 million in 2009 to $8.6 million in 2010 due to a transition from research and development activities to activities associated with cost of revenues and as a result of capitalizing expenses associated with developing Ivanpah. Allocations to projects and cost of revenues increased to $4.5 million in 2010 from $1.0 million in 2009, an increase of $3.5 million, which was offset by an increase in 2010 payroll costs of $2.2 million. Headcount associated with research and development activities increased to 128 at December 31, 2010 from 79 at December 31, 2009.

Research and development costs decreased $6.9 million, or 42%, from $16.6 million in 2008 to $9.7 million in 2009. The decrease was due to $8.8 million of research and development costs incurred in 2008 related to the completion of SEDC in Israel, and was partially offset by reduced allocations to cost of revenues of $1.2 million and an increase in salaries and related expenses of $0.5 million in 2009. Headcount associated with research and development activities increased to 79 at December 31, 2009, from 64 at December 31, 2008.

Project Development

Project development costs increased $5.8 million, or 47%, to $18.2 million from $12.4 million in 2009 due primarily to an increase in direct and indirect costs of project development of $10.5 million, increased salaries and related expense of $4.1 million and an increase of $1.2 million in consulting fees. These increases were partially offset by allocations to capitalized project costs in the amount of $11.3 million.

Project development costs increased $4.0 million, or 48%, to $12.4 million in 2009 from $8.4 million in 2008 due primarily to an increase in direct costs of project development of $3.2 million, increased salaries and related expense of $4.5 million, an increase of $0.8 million in consulting fees and increased travel related costs of $0.9 million. These increases were partially offset by allocations to capitalized project costs in the amount of $5.6 million.

Marketing, General and Administrative

Marketing, general and administrative costs increased $10.1 million, or 71%, to $24.4 million in 2010 from $14.3 million in 2009 due to increased legal and consulting fees of $10.8 million, increased compensation related expense of $3.2 million and increased other administrative costs of $2.3 million. These increases were partially offset by an increase of $6.4 million in capitalized project costs to $7.6 million in 2010 from $1.2 million in 2009. Headcount associated with marketing, general and administrative increased to 98 at December 31, 2010 from 59 at December 31, 2009.

Marketing general and administrative costs increased $3.7 million, or 35%, to $14.3 million in 2009 from $10.6 million in 2008 due to increased legal and consulting fees of $1.3 million and

increased compensation related expense of $2.0 million. These amounts were partially offset by a $0.2 million increase in allocated project costs to $1.2 million in 2010 from $1.0 million in 2009. Headcount associated with marketing, general and administrative increased to 59 at December 31, 2009 from 41 at December 31, 2008.

Interest Income (Expense), Net

Interest income (expense), net decreased $1.8 million from $(0.2) million in 2009 to $(2.0) million in 2010 related to interest and other charges on a $75.0 million credit facility entered into in October 2010, interest related to the Hercules term loan entered into in December 2010 and long-term debt associated with project development.

Interest income (expense), net decreased $1.8 million from $1.7 million in 2008 to $(0.1) million in 2009 primarily due to lower interest rates and lower average cash balances in 2009.

Other Income (Expense)

Other income (expense) decreased $0.8 million from $0.3 million in 2009 to $(0.5) million in 2010 due to net transaction losses on our foreign currency-denominated assets and liabilities.

Other income (expense) increased $0.8 million from $(0.5) million in 2008 to $0.3 million in 2009 due to net transaction gains on our foreign currency-denominated assets and liabilities.

Liquidity and Capital Resources

As of September 30, 2011, our principal sources of liquidity were our cash and cash equivalents in the amount of $238.7 million that were primarily held or invested in demand deposit accounts and money market funds. Our primary source of cash historically has been proceeds from the sales of convertible preferred stock, short-term borrowings and sales of solar thermal systems and services. Through September 30, 2011, we had raised $506.8 million, net of issuance costs and placement fees, from the issuance of convertible preferred stock. As of September 30, 2011, we had $44.7 million of outstanding debt, net of discounts. Since inception through the year ended September 30, 2011, we had accumulated net operating losses of $281.0 million.

As of September 30, 2011, our subsidiaries in Israel held approximately $58.6 million in cash and cash equivalents. Currently, there are no general restrictions on the transfer of these funds from our foreign subsidiaries to BrightSource Energy, Inc., the parent. To the extent transfers from Israel are deemed dividends on earnings or repayment of interest on intercompany loans, we are subject to withholding for Israeli taxes.

We are required to maintain cash balances that are restricted or pledged for various security provisions associated with certain commercial agreements (e.g., equipment purchases, service contracts, operating leases, performance guarantees, power purchase agreements and project development security). As such, we have pledged cash in support of letters of credit, escrow agreements and control agreements with respect to future payments and deposit obligations. The classification of the amounts are reported in our consolidated balance sheets as current or long-term are based on the timing of when the cash will be contractually released.

We believe that our current cash, cash equivalents, cash flows from operating activities and access to the capital markets will be sufficient to meet our working capital, capital expenditure and our share of project equity needs for at least the next 12 months.

Capital Expenditures

During the years ended December 31, 2008, 2009, 2010, and the nine months ended September 30, 2010 and 2011, we used $3.7 million, $17.7 million, $92.5 million, $45.6 million and $99.4 million in cash, respectively, to fund capital expenditures, primarily related to continued investments in capitalized project costs associated with Ivanpah, Rio Mesa Solar, and Hidden Hills Ranch.

Cash Flows


	Year Ended December 31,									Nine Months Ended September 30,
	2008			2009			2010			2010			2011 (1)
							(as restated)
	(in thousands)
Cash flows provided by (used in):
Operating activities	$	(26,663	)	$	(51,504	)	$	(64,105	)	$	(47,598	)	$	74,483
Investing activities	$	(11,464	)	$	(30,668	)	$	(191,271	)	$	(86,265	)	$	(3,389	)
Financing activities	$	114,404		$	(1,561	)	$	274,381		$	165,598		$	129,869

(1)

Subsequent to the issuance of our consolidated financial statements for the three-month period ended March 31, 2011, and the six-month period ended June 30, 2011, we determined that there was a misclassification of certain deposit and restricted cash payments in the consolidated statement of cash flows reported for these periods. Accordingly, for the three-month period ended March 31, 2011, net cash used in operating activities should have been $39.8 million (compared to $28.8 million as previously reported) and net cash used in investing activities should have been $87.5 million (compared to $98.5 million as previously reported); for the six-month period ended June 30, 2011, net cash provided by operating should have been $70.3 million (compared to $141.4 million as previously reported) and net cash provided by investing activities should have been $19.5 million (compared to net cash used in investing activities of $51.6 million as previously reported). The September 30, 2011 cash flow information set forth in the above table gives effect to such corrections.

Comparison of the Nine Months Ended September 30, 2010 and 2011

Operating Activities

Net cash provided by (used in) operating activities was $(47.6) million for the nine months ended September 30, 2010 compared to $74.5 million for the nine months ended September 30, 2011. Cash provided during the nine months ended September 30, 2011 was primarily related to payments received for our solar thermal technology supply and services contracts, offset partially by cash paid to our suppliers and employees as a result of spending across all functions for construction of the Coalinga Solar-to-Steam for EOR project, sourcing, engineering services and manufacture of Ivanpah scope of supply, payments for deposits, and payments for costs to close our Ivanpah financing in April 2011.

We have historically experienced negative cash flows from operations. As we continue to expand our business and build our infrastructure both in the United States and internationally, we may continue to experience negative cash flows from operations. Our cash flows from operating activities are significantly affected by our cash investments to support the growth of our business in areas such as research and development, project development and marketing, and general and administrative. Our operating cash flows are also affected by our working capital needs to support sales growth, including cash deposits to suppliers, and to support performance obligations, personnel related expenditures, accounts payable and other current assets and liabilities.

Investing Activities

Net cash used in investing activities was $86.3 million for the nine months ended September 30, 2010 compared to $3.4 million for the nine months ended September 30, 2011. Cash usage during the nine months ended September 30, 2011 was primarily related to purchases of property, plant and equipment of $14.7 million, payments of $12.1 million for deposits, and payments for capitalized project costs of $84.7 million, offset partially by $105.5 million we received in a cash distribution from the Ivanpah transaction.

Financing Activities

Net cash provided by financing activities was $165.6 million for the nine months ended September 30, 2010 compared to $129.9 million for the nine months ended September 30, 2011. Financing activities for the nine months ended September 30, 2011 included net proceeds of $170.9 million from our Series E preferred stock financings, $16.7 million of borrowings under our term loan, and $20.0 million of borrowings under our BDC Ivanpah loan, offset by a $75.0 million repayment of our credit facility.

Comparison of the Years Ended December 31, 2008, 2009 and 2010

Operating Activities

Net cash used in operating activities was $64.1 million in 2010 compared to $51.5 million in 2009. Cash usage during 2010 was primarily related to cash paid to our suppliers and employees as a result of spending across all functions due to the construction of the Coalinga Solar-to-Steam for EOR project and commencement of construction of Ivanpah.

Net cash used in operating activities was $51.5 million in 2009 compared to $26.7 million in 2008. Cash usage during 2009 was primarily related to cash paid to our suppliers and employees as a result of increased spending across all functions due to the construction of the Coalinga Solar-to-Steam for EOR project facility.

Investing Activities

Net cash used in investing activities was $191.3 million in 2010 compared to $30.7 million in 2009. Cash usage during 2010 was primarily related to purchases of equipment of $9.7 million, payments for deposits of $36.9 million, capitalized project costs of $82.8 million and increases in restricted cash of $61.9 million.

Net cash used in investing activities was $30.7 million in 2009 compared to $11.5 million in 2008. Cash usage during 2009 was primarily related to purchases of equipment of $5.0 million, payments for deposit of $7.3 million, capitalized project costs of $12.6 million and increases in restricted cash of $5.8 million.

Financing Activities

Net cash provided by financing activities was $274.4 million in 2010 compared to net cash used of $1.6 million in 2009. Financing activities in 2010 included proceeds of $162.8 million from our Series D and E preferred stock financings, $20.6 million from the issuance of common stock in association with our Series D preferred stock financing, $15.5 million from convertible note payable, of which the Company repaid $2.6 million and the remaining outstanding amount was converted to Series D preferred stock, $75.0 million of borrowings under our credit facility and $8.3 million of borrowings under our term loan.

Net cash used in financing activities was $1.6 million in 2009 compared to net cash provided of $114.4 million in 2008. Financing activities for 2009 consisted primarily of $1.4 million in costs associated with obtaining a DOE-guaranteed loan. Financing activities in 2008 included proceeds of $114.5 million from our Series C preferred stock financing.

Debt Obligations

Credit Facility

On October 4, 2010, we entered into a Credit and Guaranty Agreement, or the Credit Agreement, with certain of our wholly-owned domestic subsidiaries, as guarantors, and others of our subsidiaries which may in the future be designated as borrowers pursuant to the Credit Agreement, and Goldman Sachs Bank USA, Citicorp North America, Inc. and Deutsche Bank AG, New York Branch. The Credit Agreement provided us with a senior secured credit facility in an aggregate available amount of $75.0 million. In connection with the Credit Agreement, we also entered into a pledge and security agreement with each of the other grantors and Goldman Sachs Bank USA, as collateral agent.

At December 31, 2010, we had drawn $75.0 million, which included $4.1 million in prepaid interest and $2.1 million in debt issuance costs. As of December 31, 2010, based on applicable indices, the weighted-average borrowing rate under the credit agreement was 7.4%.

In connection with the closing of Ivanpah financing in April 2011, the borrowings under this Credit Agreement were repaid in-full and the Credit Agreement was terminated.

Term Loan

On December 28, 2010, we entered into a Loan and Guaranty Agreement, or the Initial Hercules Loan Agreement, with certain of our wholly-owned domestic subsidiaries, as guarantors, and Hercules Technology Growth Capital, Inc., and Hercules Technology II, L.P., or collectively, the Initial Lenders, pursuant to which the Lenders committed to provide us with a term loan in the amount of $25.0 million, which we refer to as the Initial Hercules Term Loan. In connection with the Initial Hercules Term Loan Agreement, we also entered into a pledge and security agreement dated December 28, 2010 among the Company, each of the guarantors under the Hercules Loan Agreement and Hercules Technology Growth Capital, Inc., as collateral agent, and associated security or deposit control agreements.

The Initial Hercules Term Loan consisted of a Term Loan A and Term Loan B. The Term Loan A was for the principal amount of $11.2 million, and Term Loan B was for the principal amount of $13.8 million, for an aggregate amount of $25.0 million. As of December 31, 2010, we had drawn $8.3 million of the $25.0 million Initial Hercules Term Loan, and drew the remaining $16.7 million balance in January 2011. As of December 31, 2010 and September 30, 2011, based on applicable indices, the weighted-average borrowing rate under the Initial Hercules Loan Agreement was 11.0% for Term Loan A and 12.8% for Term Loan B, for both periods.

As additional consideration for providing the Initial Hercules Term Loan, we provided the Lenders with a warrant that, as amended, entitles them to a number of shares of our Series D preferred stock equal to the quotient derived by dividing $875,000 by the Exercise Price. The “Exercise Price” is equal to the lower of (a) $6.7246 per share if such warrant is exercised for shares of Series D preferred stock or (b) the price per share paid in the next institutional equity financing prior to an initial public offering. As of December 31, 2010 and September 30, 2011, based on the Series D convertible stock price, we calculated the warrant would be exercisable for 130,119 shares of Series D preferred stock.

On October 7, 2011, we entered into a Loan and Security Agreement, or the New Hercules Revolving Loan Agreement, with certain of our wholly-owned domestic subsidiaries, as guarantors, and

Hercules Technology Growth Capital, Inc. and Hercules Technology III, L.P., or collectively, the New Lenders, pursuant to which the New Lenders committed to provide us with a revolving loan in the amount of up to $35.0 million, which we refer to as the New Hercules Revolving Loan. We drew down $25.0 million at the closing of the New Hercules Revolving Loan Agreement to pay off the Initial Hercules Term Loan in full. We will be eligible to borrow up to an additional $10.0 million after the closing of an initial public offering which results in aggregate proceeds of at least $100.0 million, or Qualified IPO. The New Hercules Revolving Loan matures on November 1, 2012.

The New Hercules Revolving Loan bears interest at a floating rate of the greater of (a) prime plus 7.25% and (b) 10.5%, but all advances after the completion of a Qualified IPO will bear interest at a floating rate of the greater of (a) prime plus 5.75% and (b) 9%. If we do not complete a Qualified IPO by March 30, 2012, the New Hercules Lenders can elect to receive (a) $750,000 or (b) a warrant to purchase 144,265 shares of our Preferred Stock or Common Stock at an exercise price of $8.6646 per share.

BrightSource Construction Management, Inc., BrightSource Asset Holdings, LLC and each of our domestic subsidiaries formed after the date of the New Hercules Revolving Loan Agreement (other than certain inactive subsidiaries) are required to be a guarantor under the New Hercules Revolving Loan Agreement. In addition, we have pledged all of our equity interests in each of our subsidiaries as collateral for the New Hercules Revolving Loan (except that our pledge of equity interests in non-U.S. entities is limited to 66% of such equity interests), and each future guarantor, if any, will be required to execute a similar pledge agreement. We and the existing guarantors have pledged certain of our and their intellectual property assets in favor of Hercules Technology Growth Capital, Inc., as collateral agent, and we and BrightSource Construction Management, Inc. have entered into security or deposit control agreements with the collateral agent.

The New Hercules Revolving Loan Agreement contains various affirmative and negative covenants which we must comply with, including without limitation a minimum liquidity covenant, limitations on indebtedness and limitations on dividends and other restricted payments. The Initial Hercules Term Loan contained substantially similar covenants. As of December 31, 2010 and September 30, 2011, we were, and we are currently, in compliance with these covenants.

BDC Ivanpah Loan

In April 2011, one of our wholly-owned subsidiaries entered into a loan agreement with BDC Ivanpah for $20.0 million. The loan matures on April 8, 2016 and is subject to mandatory prepayments in the event that our loan coverage ratio falls below 2.25:1. As of September 30, 2011, we are in compliance with the loan coverage ratio and, as such, are not subject to any mandatory prepayments. The weighted average interest rate for the nine months ended September 30, 2011 on the BDC Ivanpah loan was 16.5%.

CMB Loan

On November 21, 2011, our wholly-owned subsidiary BrightSource Ivanpah Fundings, LLC, or Fundings, entered into a Loan Agreement with CMB Infrastructure Investment Group VII, LP, or CMB, pursuant to which CMB agreed to provide Fundings with a term loan of up to $90 million, which we refer to as the CMB Loan. We have provided a parent guaranty for Fundings’ obligations under the CMB Loan, and Fundings has given a security interest to CMB in all of Fundings’ cash flow from the Ivanpah project.

The CMB Loan is funded by individuals seeking permanent resident status in the United States through the “EB-5” visa program. Under this program, foreign persons making qualified investments that create jobs in the United States can obtain permanent residency.

The CMB Loan will be funded when the initial phase of the EB-5 application process is complete, which is expected to occur between April and September 2012. The initial advance on the CMB Loan will be used to repay in full the BDC Ivanpah loan, with the remaining proceeds being used by us. The CMB Loan bears interest at 5% annually, and quarterly interest payments are due until maturity, which is six years from the initial funding date. Due in part to the requirements of the EB-5 program, Fundings’ ability to prepay the loan is generally restricted for forty-two months after the initial funding date.

An escrow account supports the CMB Loan, and any cash flow from the Ivanpah project (including the proceeds of any tax equity financing of our interest in the Ivanpah project) will be deposited into the escrow account and held until the loan is repaid, or used to make interest payments or prepayments of principal. We are required to deposit $5 million into the escrow account on or before December 31 of each of 2014, 2015, 2016, and 2017, plus we are required to deposit into the escrow account the amount of any tax benefits we use from the Ivanpah project.

Contractual Obligations

The following table sets forth, as of September 30, 2011, certain significant cash obligations that will affect our future liquidity (in thousands):


Contractual Obligations	Total		Less than 1 year		1-3 Years		3-5 Years		More than 5 Years
Debt obligations(1)	$	44,675	$	24,675	$	—	$	20,000	$	—
Interest payments on debt obligations(2)		22,539		893		13,730		7,916		—
Operating leases		11,288		1,585		8,212		1,491		—
Land Lease(3)		—		—		—		—		—
Purchase order for goods and services		33,666		20,315		13,351		—		—
Construction related activities		290,711		123,980		166,731		—		—

Total	$	402,879	$	171,448	$	202,024	$	29,407	$	—

(1)	On October 17, 2011, the Initial Hercules Term Loan was refinanced. For further information, see Note 20 to our consolidated financial statements.

(2)	The interest rates used to determine interest payments on debt obligations as of September 30, 2011 are more fully described in Note 8 to our consolidated financial statements.

(3)	On October 26, 2011, we submitted a notice of termination to the landlord of a ground lease for one of our development sites in Arizona. For further information, see Note 20 to our consolidated financial statements.

The following table sets forth, as of December 31, 2010, certain significant cash obligations that will affect our future liquidity (in thousands):


Contractual Obligations	Total		Less than 1 year		1-3 Years		3-5 Years		More than 5 Years
Debt obligations	$	86,392	$	78,750	$	7,642	$	—	$	—
Interest payments on debt obligations(1)		3,609		2,482		1,127		—		—
Operating leases		4,526		1,859		2,309		358		—
Land leases		12,916		715		870		870		10,461
Purchase order for goods and services		5,120		5,120		—		—		—
Construction related activities		1,680,049		813,767		866,282		—		—

Total	$	1,792,612	$	902,693	$	878,230	$	1,228	$	10,461

(1)	The interest rates used to determine interest payments on debt obligations as of December 31, 2010 are more fully described in Note 8 to our consolidated financial statements.

Obligations include significant agreements or purchase orders to purchase goods or services that are enforceable, legally binding and where the significant terms are specified. Where a minimum purchase obligation is stipulated, as in the case of certain supply agreements, the amounts included in the table reflect the minimum purchase amounts. Purchase obligations that are cancellable without significant penalty are not included in the table.

Post-Ivanpah Closing Contractual Obligations

Following the closing of Ivanpah on April 5, 2011, we agreed to guarantee and support certain contractual obligations of our subsidiaries and the Ivanpah project, including the following:

Solar Field Guarantees: We have guaranteed the obligations of our subsidiaries, BrightSource Construction Management, Inc., or BSCM, and BrightSource Operations (Israel), Ltd., or BSOI, under the solar field agreements and solar field supply contracts pursuant to which we are providing equipment, technology and services to Ivanpah. Under these contracts, BSCM and BSOI are obligated to fund an escrow account to support potential delivery and performance damages. The account will be funded with a total of $108.6 million over the first year of construction following the closing by diverting a portion of payments to BSCM and BSOI under the solar field agreements and solar field supply contracts to that escrow. We have guaranteed that the account will be funded in accordance with the schedule, and if the payments diverted from BSCM and BSOI are less than projected, we are permitted to use up to $50.0 million of our common stock based on the then current fair market value (subject to a maximum of 7,363,711 shares) to bridge funding gaps if we should so elect. Assuming construction proceeds on schedule, approximately 30% of the escrow will be released upon substantial completion of Ivanpah (i.e., the amount reserved to cover potential delay damages). The remainder will be released if other potential BSCM payments under the solar field agreements (i.e., system performance and warranty obligations) are either not payable because there are no claims or, if there are claims, BSCM or we pay them directly. We would expect to know whether these additional funds will be released by completion of the ramp-up period for Ivanpah, which occurs over the first three years of operations of each of the three project phases.

Cost Overrun Funding: To the extent Ivanpah’s costs exceed an amount equal to the base equity contribution obligations of the Ivanpah equity owners, we and the other equity owners have agreed to fund a 3% overrun contingency, known as the funded overrun equity, on a pro-rata basis. If the funded overrun equity is insufficient to cover the cost overruns for the completion of Ivanpah, the Company must fund all further cost overruns until Ivanpah’s construction is completed except to the extent the risk of such construction costs are borne by the contractors under fixed-price contracts.

Treasury Cash Grant and ITC Indemnity Obligations: We have guaranteed certain indemnity obligations in the event the Treasury Cash Grant is recaptured by the IRS, which can occur if certain prohibited ownership transfers are made or if we were to claim investment tax credits in violation of the loan and funding agreements. Also, if the Treasury Cash Grant is significantly lower than expected such that the DOE’s “debt service reserve” of approximately $57 million were to not be funded, as expected, by the Treasury Cash Grant, we would be required to fund this debt service reserve with our own cash. We are permitted to use up to $32.7 million of our common stock (subject to a maximum of 4,817,319 shares) to bridge funding gaps if we should so elect.

Sponsor Support: Pursuant to a sponsor support agreement, we have agreed to cause BSCM, BSOI and BSII to maintain at all times sufficient capital to fulfill all of their respective obligations under the various project agreements, including schedule and performance warranties, performance obligations, escrow obligations and solvency requirements.

Bechtel Deferred Payment Guaranty: Pursuant to a deferred payment guaranty with Bechtel, we are guaranteeing a payment of approximately $10 million that Bechtel has agreed to defer until payment of the Treasury Cash Grant. If we were to be required to pay under this guaranty, the Ivanpah Group would repay the amount through distributions.

Apart from the obligations addressed above, we do not anticipate any material impact on our liquidity and/or capital resources.

Off-Balance Sheet Arrangements

During 2008 and the ten-month period ended October 30, 2009, we had a partial ownership interest in Solar Partners II, LLC, or SPII. We accounted for this ownership interest under the equity method of accounting as discussed in Note 5 to our consolidated financial statements (“SPII Equity Method Investment”). On October 30, 2009, we acquired the remaining equity interest in this entity and, as such, this entity is consolidated in our consolidated financial statements for the period from November 1, 2009 to April 5, 2011. See Note 7 to our consolidated financial statements (“2009 Asset Acquisition”) for additional details.

In April 2011, we closed the financing of Ivanpah, to which SPII is a party with certain third-party equity investors and the DOE. See note 7 to our consolidated financial statements (“2011 Ivanpah Transaction”) for additional details.

Impact of Inflation

Inflation did not have a material impact on our results of operations for the years ended December 31, 2008, 2009, 2010 and for the nine months ended September 30, 2011. There can be no assurance that future inflation will not have an adverse impact on our operating results and financial condition.

Disclosure about Market Risk

Foreign Currency Risk

We have significant expenses, assets and liabilities that are denominated in foreign currencies. A majority of our employees are located in Israel, therefore, a substantial portion of our payroll as well as certain other operating expenses are paid in the Israeli shekel. Additionally, we purchase materials and components from suppliers in Asia and Europe. While we typically negotiate our agreements such that we pay these suppliers in U.S. dollars, their costs may be based upon the local currency of the country in which they operate. All of our revenues are currently valued in U.S. dollars; however, as we expand our international presence and levels of activity in other countries, we anticipate that revenues may be denominated in the local currency of those countries.

In the past, exchange rate fluctuations have had an impact on our business and results of operations of our Israeli subsidiaries. For example, the average exchange rate for the Israeli Shekel to the U.S. Dollar decreased by 9% for 2009 relative to 2008, increased by 5% for 2010 relative to 2009 and decreased by 6% in the first nine months of 2011 relative to the first nine months of 2010. Timing of Shekel-based payments, hedging and other activities we have utilized to mitigate currency risk, U.S. Dollar-based sourcing initiatives and changes in the relative economic activity over time between the United States and Israel all impact the degree to which these currency fluctuations impact our operations. The following table presents the estimated U.S. Dollar (in thousands) and percentage impact that currency movements have had on our cost of revenues and operating expenses.


	Year Ended December 31																Nine Months Ended September 30
	2008					2009						2010					2010					2011
	Currency Impact		% Impact			Currency Impact			% Impact			Currency Impact		% Impact			Currency Impact		% Impact			Currency Impact		% Impact
Unfavorable (favorable) impacts:
Revenues	$	—		—		$	—			—		$	—		—		$	—		—		$	—		—
Cost of revenues		868		5.0	%		(501	)		(2.6	)%		292		0.9	%		390		1.7	%		769		1.0	%

Gross loss		868		8.6	%		(501	)		(6.7	)%		292		1.6	%		390		3.6	%		769		8.0	%

Operating expenses:
Research and development		2,114		12.7	%		(820	)		(8.4	)%		399		4.7	%		217		3.6	%		855		6.2	%
Project development		360		4.3	%		(128	)		(1.0	)%		80		0.4	%		44		0.4	%		237		1.2	%
Marketing, general and administrative		181		1.7	%		(341	)		(2.4	)%		279		1.1	%		147		0.9	%		378		1.3	%

		2,655		7.4	%		(1,289	)		(3.5	)%		758		1.5	%		408		1.2	%		1,470		1.7	%
Loss from operations		3,523		7.7	%		(1,790	)		(4.1	)%		1,051		1.5	%		799		1.7	%		2,240		2.4	%

Net loss		3,523		7.5	%		(1,790	)		(4.1	)%		1,051		1.6	%		799		1.8	%		2,240		2.6	%

We have not defined derivatives used to historically manage currency risk as hedges; therefore, adjustments to the fair values of forward contracts have been recognized through earnings as “Other income (expense), net” in our consolidated statements of operations. Losses were recognized from foreign currency forward contracts of $0.6 million and $0.4 million in 2008 and 2009, respectively. We did not utilize derivative financial instruments to manage currency risk in 2010 and for the nine months ended September 30, 2011.

Exchange rate fluctuations associated with the shekel-denominated financial assets positively impacted our cash flows by $0.8 million in fiscal year 2009 and negatively impacted our cash flows by $0.6 million in fiscal year 2010. Although we cannot predict the impact of future exchange rate fluctuations on our business or results of operations, we believe that we may have increased risk associated with currency fluctuations in the future as our operations expand and expenditures in currencies other than the U.S. dollar increases.

Interest Rate Risk

We had cash and cash equivalents totaling $37.8 million and $238.7 million as of December 31, 2010 and September 30, 2011, respectively. These amounts were held or invested in demand deposit accounts and money market funds. The cash and cash equivalents are held for working capital purposes. We do not enter into investments for trading or speculative purposes. We believe that we do not have any material exposure to changes in the fair value as a result of changes in interest rates due to the short-term nature of our cash equivalents. Changes in interest rates, however, would impact future investment income.

Investors in solar thermal projects using our systems are exposed to interest rate risk because construction of these projects typically depends on debt financing. An increase in interest rates could

make it difficult for projects to secure financing on favorable terms, or at all, and thus lower demand for our systems. An increase in interest rates could also require us to lower our margins on system sales in order to sell our equipment to the projects.

Interest rate risk also refers to our exposure to movements in interest rates associated with our interest bearing liabilities. The interest bearing liabilities are denominated in U.S. dollars and the interest expense is based on various underlying indices plus an additional margin, depending on the respective lending institutions. Any change in these underlying indices would increase our interest expense. Interest expense in 2009 and 2010 would not have been materially impacted for 2009 and 2010 due to the timing of these borrowings and the relatively short periods such borrowings were outstanding; however, increases in these rates could significantly increase our interest expense in future periods. For example, a change in the indices underlying our variable rate borrowings of 100 basis points would increase our interest expense by $250,000 per year, assuming our variable interest bearing liabilities were to remain constant at September 30, 2011 levels.

Critical Accounting Policies and Estimates

Our consolidated financial statements included elsewhere in this prospectus are prepared in accordance with accounting principles generally accepted in the United States. The preparation of the consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, costs and expenses and related disclosures. We base our estimates on historical experience, as appropriate, and on various other assumptions that we believe to be reasonable under the circumstances. Changes in the accounting estimates are reasonably likely to occur from period to period. Accordingly, actual results could differ significantly from the estimates made by our management.

We evaluate our estimates and assumptions on an ongoing basis. To the extent that there are material differences between these estimates and actual results, our future financial statement presentation, financial condition, results of operations and cash flows will be affected. We believe that the following critical accounting policies involve a greater degree of judgment and complexity than our other accounting policies. Accordingly, these are the policies we believe are the most critical to understanding and evaluating our consolidated financial condition and results of operations. Our significant accounting policies are more fully described in Note 2 to our consolidated financial statements set forth in this prospectus. Our critical accounting policies include:

Revenues and Cost of Revenues

We typically sell our products and services to utility-scale solar thermal projects, contractors engaged by the project owners or project companies. We recognize revenue when persuasive evidence of an arrangement exists, delivery of the product or service has occurred, the sales price is fixed and determinable, collectability of the resulting receivable is reasonably assured and the rights and risks of ownership have passed to the customer. We may have significant post-shipment obligations, including installation, training and customer acceptance clauses, including guarantees of project performance and warranties that could have an impact on revenue recognition.

Revenues generated from the construction of a solar thermal energy facility, including the associated equipment and services, on behalf of third parties, are recognized using the percentage- of-completion method of accounting. The percentage-of-completion method requires estimates of future costs over the full term of the project. Such cost estimates are made by management based on prior operations and specific project characteristics and designs. Historically, we have had significant cost variances between our cost estimates and actual costs incurred on our Coalinga Solar-to-Steam for EOR contract. The revisions to the estimated loss primarily related to redesign work and change

orders under the terms of the contract that could not be passed on to Chevron. The Company evaluates its estimates at least quarterly and updates its estimates based on the changes to the project. Changes in job performance, job conditions, and estimated profitability, including those arising from performance guarantees and warranties in relevant contracts and final contract settlements, may result in revisions to costs and revenues and are recognized in the period in which the revisions are determined. Provisions for estimated losses relating to contracts are made in the period in which such losses are determined.

We do not recognize revenue for products and services sold to consolidated entities. For unconsolidated entities in which we are investors, we reduce the revenue recognized in proportion to our ownership interest.

We provide warranties and guarantees ensuring our products are suitable and meet certain quality, delivery and performance parameters. We accrue reserves to satisfy any potential product failure or failure to achieve specifications. We review these reserves at least quarterly to ensure that our accruals are adequate to meet any potential failures or inability to meet any required parameters and adjust our estimates as needed. Due to our limited operating history our experience is limited and, as such, the adjustments we record may be material. Our customers may require us to post letters of credit or other security in order to guarantee performance under the relevant contracts.

Capitalized Project Costs

We capitalize costs incurred in connection with the development of solar thermal projects upon meeting specific project viability criteria. Evidence of project viability includes securing the site by option, lease, or acquisition; the evaluation of studies supporting the suitability of a site for the solar thermal project; and an off-take agreement or a viable economic analysis. Our viable economic analysis generally assesses the ability of the project to meet our required internal rates of return for project investments through expected cash distributions and other economic benefits (e.g., tax benefits) associated with the project, taking into account all capital, development and operating costs of the project, including debt financing costs. Upon satisfaction of these criteria, our management and project managers determine whether a project has met a project economic viability threshold and assess whether the specific project is probable to progress to full development and will ultimately realize future positive cash flows. Project costs incurred prior to meeting these thresholds are expensed as incurred. Upon meeting these thresholds, costs directly related to project development, including associated overhead, are capitalized. Capitalized project costs do not include administrative costs, marketing costs or other costs not directly associated with the development of the solar thermal project.

Consolidation of Special Purpose Entities

We typically form special purpose entities to capture all costs of developing a solar thermal project, which we refer to as project companies. These may be deemed to be variable interest entities, or VIEs. If the entity is deemed to be a VIE, we perform an analysis to determine whether our variable interest or interests give us a controlling financial interest. We evaluate our ability to direct the activities of the entity and our obligation to absorb losses or receive benefits from the entity. If we determine that we are the primary beneficiary, we consolidate the entity in our financial statements. We do not recognize revenue for the supply of products and services to a project if we determine that we are the primary beneficiary.

During the initial development phases, we are typically the sole investor in these entities and are the primary beneficiary. As a project proceeds other partners may invest in the VIE. As other partners acquire interests in the VIE, we reevaluate whether we remain the primary beneficiary. If we should determine that we are no longer the primary beneficiary, we will deconsolidate the entity and recognize any gain or loss associated with the deconsolidation event.

Project Divestiture

When we cease to have a controlling financial interest in a subsidiary whether by sale, receipt of additional investment, sale of equity interests or contribution of assets or other transfer of an interest in a project company we first evaluate whether the transaction should be accounted for under the standard of deconsolidation of a subsidiary or a group of assets. If we have control of land or land rights, we further evaluate whether the assets are determined to be within the scope of the guidance for real estate sales. As part of this determination, we consider both (i) the stage of development of the project and (ii) the composition and the fair value of assets transferred or contributed within the project companies at the date of the transaction to determine whether a significant amount of the fair value of the assets is real estate or non-real estate. If the assets are determined to be in the scope of the guidance for real estate sales, the related net assets may continue to be presented in our consolidated financial statements until all requirements of the accounting standard for real estate sales have been satisfied. If the transaction is not within the scope of the standard for real estate sales, and we no longer exercise control over the project company or assets, we will typically deconsolidate the project company and will derecognize the related net assets associated with the project.

Share-Based Compensation

Our share-based compensation expense was as follows:


	Year Ended December 31,						Nine Months Ended September 30,
	2008		2009		2010		2010		2011
	(in thousands)
Research and development	$	120	$	218	$	264	$	193	$	577
Project development		273		374		675		465		863
Marketing, general and administrative		575		816		1,398		792		2,197

Total	$	968	$	1,408	$	2,337	$	1,450	$	3,637

We recognize compensation expense related to share-based transactions, including the awarding of employee stock options, based on the grant date estimated fair value. We amortize the fair value of the employee stock options on a straight-line basis over the requisite service period of the award, which is generally the vesting period.

In future periods, our share-based compensation expense is expected to increase as a result of our existing unrecognized share-based compensation still to be recognized and as we issue additional share-based awards in order to attract and retain employees and nonemployee consultants.

Significant Factors, Assumptions and Methodologies Used in Determining Fair Value

We utilize the Black-Scholes option pricing model to estimate the fair value of our share-based payment awards. The Black-Scholes option pricing model requires inputs such as the expected term of the grant, expected volatility and risk-free interest rate. Further, the forfeiture rate also affects the amount of aggregate compensation that we are required to record as an expense. These inputs are subjective and generally require significant judgment.

The fair value of employee stock options was estimated using the following weighted average assumptions:

Weighted average assumptions used to estimate the fair value of stock options granted to employees were as follows:


	Year Ended December 31,									Nine Months Ended September 30, 2011
	2008			2009			2010			Nine Months Ended September 30, 2011
Risk-free interest rate		3.27	%		2.78	%		2.24	%		2.29	%
Expected term (in years)		6.50			6.48			6.11			6.45
Expected volatility		102	%		90	%		91	%		89	%
Dividend yield		—			—			—			—

Weighted average assumptions used to estimate the fair value of stock options granted to non-employees were as follows:


	Year Ended December 31,									Nine Months Ended September 30, 2011
	2008			2009			2010			Nine Months Ended September 30, 2011
Risk-free interest rate		2.24	%		3.85	%		3.30	%		2.91	%
Expected term (in years)		9.71			9.63			9.66			9.22
Expected volatility		102	%		90	%		91	%		89	%
Dividend yield		—			—			—			—

We have estimated the expected term, which represents our best estimate of the period of time from the grant date that we expect the stock options to remain outstanding, of all of our stock options that qualify for such estimation using the simplified method, as provided under authoritative guidance. The simplified method is calculated as the average of the time to vest and the contractual life of the options. We deemed it appropriate to use the simplified method as we have limited operating experience and share option exercise experience. Since we are a private entity with no historical data regarding the volatility of our common stock, the expected volatility used is based on volatility of similar publicly listed companies in comparable industries. In evaluating similarity, we considered factors such as industry, stage of life cycle and market capitalization.

Our risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for zero coupon U.S. Treasury notes with maturities approximately equal to each option’s expected term. Our expected dividend yield was assumed to be zero as we have not paid, and do not anticipate paying, cash dividends on our shares of common stock. We estimate our forfeiture rate based on an analysis of our actual forfeitures and will continue to evaluate the appropriateness of the forfeiture rate based on actual forfeiture experience, analysis of employee turnover and other factors.

Quarterly changes in the estimated forfeiture rate can have a significant effect on reported stock-based compensation expense, as the cumulative effect of adjusting the rate for all expense amortization is recognized in the period the forfeiture estimate is changed. If a revised forfeiture rate is higher than the previously estimated forfeiture rate, an adjustment is made that will result in a decrease to the share-based compensation expense recognized in the consolidated financial statements. If a revised forfeiture rate is lower than the previously estimated forfeiture rate, an adjustment is made that will result in an increase to the share-based compensation expense recognized in the consolidated financial statements.

We will continue to use judgment in evaluating the expected term, volatility and forfeiture rate related to our own share-based compensation on a prospective basis and incorporating these factors into the Black-Scholes option pricing model. Each of these inputs is subjective and generally requires significant management and director judgment. If, in the future, we determine that another method for

calculating the fair value of our stock options is more reasonable, or if another method for calculating these input assumptions is prescribed by authoritative guidance and, therefore, should be used to estimate expected volatility or expected term, the fair value calculated for our employee stock options could change significantly. Higher volatility and longer expected terms generally result in an increase to share-based compensation expense.

The following table summarizes the options granted from January 1, 2010, through the date of this prospectus:


Grant Date	Number of Options Granted		Exercise Price per Share		Fair Value per Share		Intrinsic Value Per Share
April 28, 2010		421,100	$	4.26	$	4.26		—
August 25, 2010		429,100	$	4.83	$	4.83		—
September 20, 2010		2,325,988	$	4.83	$	4.83		—
January 6, 2011*		332,400	$	6.06	$	6.06		—
January 27, 2011*		18,000	$	6.06	$	6.06		—
March 18, 2011		93,800	$	6.79	$	6.79		—
April 27, 2011		1,225,199	$	7.52	$	7.52		—
May 2, 2011		270	$	7.52	$	7.52		—
September 9, 2011		679,990	$	9.81	$	9.81		—
December 19, 2011		162,890	$	6.65	$	6.65		—
December 29, 2011		95,000	$	6.65	$	6.65		—

Stock options granted on January 6, 2011 and January 27, 2011 were granted based on the third-party valuation of our common stock as of October 31, 2010 that our compensation committee received in January 2011 (as described below). Subsequently, our compensation committee received a new valuation in March 2011 (as described below) establishing the per share fair market value for our common stock at $6.79 as of December 31, 2010. Because of the higher valuation as of December 31, 2010, in May and June 2011, we offered certain holders of outstanding options granted on January 6, 2011 and January 27, 2011 the opportunity to reprice such options to $6.79 to avoid any potential adverse tax treatment under Section 409A of the Code. The offer expired on June 27, 2011 and holders of outstanding options granted on January 6, 2011 and January 27, 2011 representing 162,400 shares (including all such holders employed in the U.S.) participated in the exchange.

All options granted by our compensation committee on the dates noted above were intended to be exercisable at the fair value of our stock based on information known at that time. The fair values of the common stock underlying our stock options have historically been determined by our compensation committee with input from management and an independent third-party valuation specialist.

In the absence of a public trading market for our common stock, our compensation committee has determined the fair value of the common stock utilizing methodologies, approaches and assumptions consistent with the American Institute of Certified Public Accountants Practice Guide, Valuation of Privately-Held-Company Equity Securities Issued as Compensation, or the AICPA Practice Guide. In addition, our compensation committee considered numerous objective and subjective factors including:

the prices for our convertible preferred stock sold to outside investors in arm’s-length transactions;

the prices of our common stock sold to investors in arm’s-length transactions;

rights, preferences and privileges of that convertible preferred stock relative to those of our common stock;

contemporaneous valuations performed by an unrelated third party;

actual operating and financial performance based on management’s estimates;

the execution of strategic and development agreements;

the hiring of key personnel;

status of projects under development;

the risks inherent in the development and expansion of our products and services;

our stage of development;

achievement of various product design milestones;

the lack of an active public market for our common and convertible preferred stock;

the likelihood of achieving a liquidity event, such as an initial public offering or a sale of our company given prevailing market conditions and the nature and history of our business;

the performance of similarly-situated companies in our industry;

trends in the renewable energy market;

industry information such as market growth and volume; and

macro-economic events.

Our compensation committee considered common stock valuations performed as of February 28, 2010, July 31, 2010, October 31, 2010, December 31, 2010 April 26, 2011, August 31, 2011 and November 30, 2011, in determining or confirming the grant date fair value of common stock. Using these valuations, and the other factors described above, our compensation committee made the following estimates of fair value of our common stock.


Valuation Date	Fair Value Per Share
February 28, 2010	$	4.26
July 31, 2010	$	4.83
October 31, 2010	$	6.06
December 31, 2010	$	6.79
April 26, 2011	$	7.52
August 31, 2011	$	9.81
November 30, 2011	$	6.65

The valuations that our compensation committee considered in determining the fair value of our common stock from February 28, 2010 through November 30, 2011 were estimated using the probability weighted expected return method, or PWERM, which considers various potential liquidity outcomes and assigns probabilities to each in order to arrive at a weighted equity value.

For each of the possible events, a range of future equity values is estimated, based on market, income and/or cost approaches over a range of possible event dates, all plus or minus a standard deviation for value and timing. For each equity and value scenario, the rights and preferences of each stockholder class are considered in order to determine the appropriate allocation of value to common shares. The value of each common share is then multiplied by a discount factor derived from the calculated discount rate and the expected timing of the event. A risk-adjusted discount rate is applied as the probability weightings in the PWERM address the success rates of each scenario. The value per common share, taking into account sensitivities to the timing of the event, is then multiplied by an estimated probability for each of the possible events. The calculated value per common share under the private company scenario is then discounted for the lack of marketability. A probability-weighted value per share of common stock is then determined.

PWERM is commonly used when a company anticipates an exit event within 12 to 18 months of its valuation date. As such, the Company believes this is a reasonable methodology as supported and reflected in the Company’s third-party valuation reports.

Discussion of Specific Valuation Inputs

We granted stock options in 2010 and 2011 with exercise prices between $4.26 and $9.81 per share. No single event caused the valuation of our common stock to increase or decrease from January 2010 to August 2011; rather, it has been a combination of factors that led to the changes in the fair value of the underlying common stock.

In April 2010, our compensation committee received a valuation of $4.26 per share of common stock as of February 28, 2010. Significant events during the period from January 2010 to February 2010 influencing this valuation included the February formal announcement by the DOE indicating their conditional commitment to provide a loan guarantee in the amount of $1.37 billion, which was subsequently increased to $1.6 billion. In addition, the first closing of our Series D preferred stock offering occurred with a value $6.7246 per share. At this first closing, $75.0 million was raised, primarily from current investors.

In August 2010, our compensation committee received a valuation of $4.83 per share of common stock as of July 31, 2010. Significant events during the period from March through July 2010 that influenced this valuation were the second, third and fourth closings of our Series D preferred stock offering in April, May and June 2010, respectively. In conjunction with the third closing of our Series D offering, we obtained a convertible note in the amount of $15.5 million with a new investor, Alstom. Valuation of the Series D offering was $6.7246 per share and included both new and existing investors.

In January 2011, our compensation committee received a valuation of $6.06 per share of common stock as of October 31, 2010. Significant events during the period from August to October 2010 were the conversion of the Alstom note into Series D preferred stock in August 2010 and our entering into a business partnership with Alstom in August 2010 to jointly market and bid on projects to design and construct solar thermal power plants in North Africa, South Africa and Southern Europe (subsequently expanded in December 2010 to include certain countries in the Middle East and in August 2011 to include India). In October 2010, we received final approval to commence construction on Ivanpah from all required governmental agencies, including the U.S. Bureau of Land Management, or BLM. NRG Solar also agreed to be the lead investor in Ivanpah in October 2010. Subsequent to receipt of the final permits for Ivanpah, we commenced construction in October 2010. On January 6, 2011 and January 27, 2011, our compensation committee approved an aggregate of 350,400 stock options based on the valuation as of October 31, 2010 that was received in January 2011. Subsequently, our compensation committee received a new valuation in March 2011 (as described below) establishing the per share fair market value for our common stock at $6.79 as of December 31, 2010. Because of the higher valuation as of December 31, 2010, in May and June 2011, we offered certain holders of outstanding options granted on January 6, 2011 and January 27, 2011 the opportunity to reprice such options to $6.79 to avoid any potential adverse tax treatment under Section 409A of the Code. The offer expired on June 27, 2011 and holders of outstanding options granted on January 6, 2011 and January 27, 2011 representing 162,400 shares (including all such holders employed in the U.S.) participated in the exchange.

In March 2011, our compensation committee received a valuation of $6.79 per share of common stock as of December 31, 2010. Significant events during November and December 2010 that influenced this valuation included the first closing of our Series E preferred stock offering in the amount of $27 million. In addition, the Company received a formal commitment for an additional $48 million, which was received in early January 2011. Additional events considered were the initial organizational meeting in contemplation of preparation of this offering, entering into a $75 million credit facility, and

the signing of the $25 million Initial Hercules Term Loan. On March 18, 2011, the compensation committee approved 93,800 stock options based on the valuation as of December 31, 2010 that was received in March 2011. In establishing the fair market value of our common stock in connection with approving these grants, the compensation committee determined that, based upon the intervening circumstances (for example, uncertainty created by the project litigation filed in January 2011, the additional funding of the Series E preferred stock financing and the uncertainty of a project finance closing for Ivanpah) between December 31, 2010, the effective date of the valuation, and March 18, 2011, the grant date, the fair market value of our common stock was not greater than the fair market value determined by the valuation received in March 2011.

In April 2011, our compensation committee received a valuation of $7.52 per share of common stock as of April 25, 2011. Significant events during January, February and March 2011 that influenced this valuation included the final closing of our Series E preferred stock offering, which totaled $200 million. In addition, we also closed the project financing for all three projects at the Ivanpah site on April 5, 2011. On April 27, 2011 and May 2, 2011, the compensation committee approved an aggregate of 1,225,469 stock options based upon this valuation. These grants included 1,069,399 stock options granted to non-executive employees as part of our annual performance and merit compensation review process.

In September 2011, our compensation committee received a valuation of $9.81 per share of common stock as of August 31, 2011. Significant events during the period between May and August 2011 that influenced this valuation included, but are not limited to, continued progress at Ivanpah and the Coalinga Solar-to-Steam for EOR project; filing the Application of Certification for the Hidden Hills Ranch Solar Electric Generating System; the introduction of SolarPLUS, which combines our solar power tower technology with two-tank molten-salt storage capabilities; and new additions to our senior management team. On September 9, 2011, the compensation committee approved an aggregate of 679,990 stock options based on this valuation.

In December 2011, our compensation committee received a valuation of $6.65 per share of common stock as of November 30, 2011. Significant events during the period between September and November 2011 that influenced this valuation included, but are not limited to, elevated volatility in financial markets, announcements of third quarter earnings from the clean-tech sector that fell short of analyst and investor expectations, meaningful reductions in renewable energy company stock prices, sector multiples compression and defensive investor posturing. Company milestones achieved during this period included continued progress at Ivanpah, commencement of operations using our solar thermal technology at the Coalinga Solar-to-Steam EOR project, filing the Application for Certification for the Rio Mesa Solar Electric Generating System and the addition of our SolarPLUS thermal energy storage capability to three of our power purchase agreements with Southern California Edison. On December 19, 2011, the compensation committee approved 162,890 stock options based on this valuation. Additionally, on December 19, 2011, the compensation committee approved a stock option grant to an individual for 95,000 shares to be effective upon the appointment of the individual as an nonemployee director, which occurred on December 29, 2011. The per share exercise price for such option is $6.65, the fair market value of a share of common stock on the effective date of the grant.

Accounting for Guarantees

We are subject to various guarantees, including guarantees related to our solar field supply contracts, guarantees related to the our equity investment in Ivanpah HoldCo and various guarantees related to our wholly-owned subsidiaries. We recognize a liability for the fair value of guarantees that meet the criteria of ASC 460—Guarantees. For those guarantees that are not within the scope of ASC 460, we apply the contingent liability model whereby we will accrue a liability if it is probable that a liability has been incurred and the amount of loss is reasonably estimable.

Estimating the fair value of these guarantees requires significant management judgment. The calculated fair values of these guarantees are subject to change if the underlying estimates and assumptions should change. These calculations are highly sensitive to changes in key assumptions and actual results may vary significantly from the current fair value estimates.

For the Bechtel Deferred Payment Guarantee that we have provided on behalf of Ivanpah HoldCo, we utilize the published corporate rate spreads for similarly bonds with similar credit ratings and tenors. If the corporate rate spreads should change, we will experience a change in fair value. For example, if there were an increase of 100 basis points in the corporate interest rate spreads would result in a corresponding change of $0.1 million in increased fair value.

The Cost Overrun Funding Guarantee, in which we have committed to funding any cost overruns in excess of a base contingency provision and a defined funded contingency overrun, is reliant on assumptions regarding the monetary value of any cost overruns and the probability that such overruns might occur. If the actual cost overruns should increase by more than 300% over our current forecast, we would be required to pay cost overruns of approximately $15.1 million. If the actual cost overruns should increase by 400% over our current forecast, we would be required to pay additional costs of approximately $61.0 million. We estimated fair value by applying a probability weighted model to the various cost outcomes and then discounted the resulting values. Such fair value was estimated to be $0.3 million as of September 30, 2011. A change in the probability weighting associated with any particular outcome would result in a different fair value. For example, if the probability of our currently identified highest cost scenario were to increase from 0.3% to 3%, we would see an increase in fair value of approximately $1.4 million.

Accounting for Income Taxes

Our global operations involve project development, manufacturing, research and development and marketing activities. Profit from non-U.S. activities is subject to local country taxes but generally not subject to United States tax until repatriated to the United States. It is currently our intention to permanently reinvest these earnings outside the United States. We record a valuation allowance to reduce our deferred tax assets to the amount that is more likely than not to be realized. We consider historical levels of income, expectations and risks associated with estimates of future taxable income and tax planning strategies that management believes are prudent and feasible in assessing the need for the valuation allowance. Should we determine that we would be able to realize deferred tax assets in the future in excess of the net recorded amount, we would record an adjustment to the deferred tax asset valuation allowance. This adjustment would increase income in the period such determination is made.

The calculation of tax liabilities involves dealing with uncertainties in the application of complex global tax regulations. We recognize potential liabilities for anticipated tax audit issues in the United States and other tax jurisdictions based on our estimate of whether, and the extent to which, additional taxes will be due. If payment of these amounts ultimately proves to be unnecessary, the reversal of the liabilities would result in tax benefits being recognized in the period when we determine the liabilities are no longer necessary. If the ultimate tax assessment is proven to be more than our estimate of tax liabilities, a further charge to earnings would result.

New Accounting Pronouncements

In October 2009, the Financial Accounting Standards Board (“FASB”) issued new standards for revenue recognition with multiple deliverables. These new standards impact the determination of when the individual deliverables included in a multiple-element arrangement may be treated as separate units of accounting. Additionally, these new standards modify the manner in which the transaction consideration is allocated across the separately identified deliverables by no longer permitting the

residual method of allocating arrangement consideration. These new standards are required to be adopted in the first quarter of 2011. The adoption of this standard had no material impact on our consolidated financial statements.

In October 2009, the FASB issued new standards for the accounting for certain revenue arrangements that include software elements. These new standards amend the scope of pre-existing software revenue guidance by removing from the guidance non-software components of tangible products and certain software components of tangible products. These new standards are required to be adopted in the first quarter of 2011. The adoption by the Company of this standard had no material impact on our consolidated financial statements.

In January 2010, the FASB issued amended standards that require additional fair value disclosures. These amended standards require disclosures about inputs and valuation techniques used to measure fair value, as well as disclosures about significant transfers, beginning in the first quarter of 2010. Additionally, these amended standards require presentation of disaggregated activity within the reconciliation for fair value measurements using significant unobservable inputs (Level 3), beginning in 2011 and is disclosed in note 3 to our consolidated financial statements.

In May 2011, the FASB issued Accounting Standards Update No. 2011-04 (“ASU 2011-04”). ASU 2011-04 changes the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements to ensure consistency between U.S. GAAP and IFRS. ASU 2011-04 also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance is to be applied prospectively beginning in the first quarter of 2012. We are currently assessing the impact that this new standard will have on our consolidated financial statements and the related footnotes.

In June 2011, the FASB issued ASU 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. ASU 2011-05 allows an entity to present components of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate but consecutive statements. ASU 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. While the new guidance changes the presentation of comprehensive income, there are no changes to the components that are recognized in net income or other comprehensive income under current accounting guidance. ASU 2011-05 is effective for fiscal years and interim periods beginning after December 15, 2011 and must be applied retrospectively. We do not believe that the adoption of ASU 2011-05 will have an impact on our consolidated balance sheet, statement of operations, or statement of cash flows.

MARKET AND INDUSTRY DATA

Unless otherwise indicated, information contained in this prospectus concerning our industry and the markets in which we operate, including our general expectations and market position, market opportunity and market size, is based on information from various sources, on assumptions that we have made that are based on those data and other similar sources and on our knowledge of the markets for our services. These sources include the Energy Information Administration, Pacific Gas and Electric Company, Southern California Edison, the U.S. Department of Energy, SBI Energy, BCC Research, Energy and Environmental Economics, Inc., the National Renewable Energy Laboratory and Emerging Energy Research. Projections, assumptions and estimates of our future performance and the future performance of the industry in which we operate are necessarily subject to a high degree of uncertainty and risk due to a variety of factors, including those described in “Risk Factors” and elsewhere in this prospectus. These and other factors could cause results to differ materially from those expressed in the estimates made by the independent parties and by us.

BUSINESS

Company Overview

Our systems use fields of tracking mirrors, known as heliostats, controlled by our proprietary software to concentrate sunlight onto a solar receiver/boiler unit to produce high-temperature steam. Once produced, the steam is used either in a conventional steam turbine to produce electricity or in industrial applications such as thermal EOR. By integrating conventional power block components, such as turbines, with our proprietary technology and state-of-the-art solar field design, projects using our systems can deliver cost-competitive, reliable and clean power when needed most. In addition, by incorporating thermal storage and integrating our technology with natural gas or other fossil fuels through a process referred to as hybridization, projects using our systems can further increase output and reliability.

In implementing systems using our proprietary technology, we partner with several parties to develop utility-scale, solar electric power plants. These parties include engineering, procurement and construction (EPC) contractors; boiler suppliers; turbine suppliers; and financing parties that may consist of strategic and/or financial investors.

The principal members of our technical team pioneered the first utility-scale solar energy plants nearly three decades ago by designing and developing 354 megawatt, or MW, of solar thermal power systems, which remain in operation today. Our technical team has moved beyond these initial solar thermal technologies by engineering a solar power tower system that provides both higher solar energy conversion efficiencies and lower costs. Our team has extensive solar thermal technical and project development expertise and has collectively developed, constructed and managed more than 25 gigawatts, or GW, of solar, wind and conventional power projects worldwide.

We have produced high-temperature steam using our technology since 2008, when we commenced operations at our 6 megawatt thermal, or MWth demonstration solar-to-steam facility, the Solar Energy Development Center, in Israel. We believe this facility has consistently produced the highest temperature and pressure steam of any solar thermal facility in the world, capable of driving highly-efficient, cost-effective turbines. This facility validated our technology and continues to provide important operational and production data.

Through our project companies, have 13 executed and outstanding long-term power purchase agreements, or PPAs, to deliver approximately 2.4 GW of installed capacity to two of the largest electric utilities in the United States, Pacific Gas and Electric Company, or PG&E, and Southern California Edison, or SCE. We believe these PPAs represent one of the largest utility-scale solar pipelines in the United States and should provide us with a significant revenue opportunity between 2013 and 2016. For

purposes of illustration, our agreements for the supply of equipment and services to the Ivanpah project, which has three PPAs totaling 377 MW, represent $672.0 million of contracted sales, which equates to approximately $1.8 million of contracted sales per MW. Consistent with our 14% ownership in Ivanpah, we will recognize 86% of any actual sales as revenue. As the first step in fulfilling our obligations under the PPAs, in October 2010, we initiated construction on Ivanpah, a project comprised of three concentrating solar thermal power plants on an approximately 3,500 acre site in California’s Mojave Desert. When commissioned, Ivanpah will have an installed capacity of 377 MW and will increase the amount of solar thermal generation capacity currently installed in the United States by over 75%.

We have an approximately 90,000 acre development site portfolio under our control in California and the U.S. Southwest that has the potential to accommodate approximately 9 GW (gross) of installed capacity. We currently have three sites in advanced development, Rio Mesa Solar and Hidden Hills Ranch, each located in California, and Sandy Valley, located in Nevada. Rio Mesa Solar consists of approximately 5,800 acres, Hidden Hills Ranch consists of approximately 3,300 acres, and Sandy Valley consists of approximately 10,000 acres. In August and October 2011, we filed Applications for Certification with the California Energy Commission for the development of solar power plants at Hidden Hills Ranch and Rio Mesa Solar, respectively.

We were initially incorporated on April 5, 2004, as Luz II, LLC, a Delaware limited liability company, and began our operations on May 1, 2006. On August 17, 2006, the LLC was converted to Luz II, Inc., a Delaware corporation, and changed its name to BrightSource Energy, Inc. in May 2007.

Industry Overview

Growing Global Demand for Electricity and Renewable Energy Technology

According to a report released in 2010 by the Energy Information Administration (EIA), global demand for electric power is expected to increase 87% from 2007 to 2035 reaching 35.2 trillion kilowatt hours. Although fossil fuels such as coal, oil and natural gas generated approximately 68% of the world’s electricity in 2007, several factors are driving the increase in demand for renewable energy sources. These factors include carbon dioxide emission reduction targets, government regulatory policies and incentives, cost, safety and environmental impacts of conventional power and the increase in long-term global energy consumption. According to the EIA, global renewable energy, excluding hydroelectric energy, constituted 2.5% of electricity generation in 2007 and is expected to increase to 7.3% in 2035. Among renewable sources of electricity, we believe utility-scale solar thermal technology has the potential to meet a significant share of the world’s growing electricity needs due to the abundant nature of solar resources and the ability to reliably produce power when needed most.

Utility-Scale Solar Energy Technologies

There are two primary categories of utility-scale solar energy technologies used to generate electricity:

Photovoltaic, or PV: An electricity-producing technology in the form of solar cells generally arranged in modules that converts sunlight directly into electricity. The principal photovoltaic (PV)

technologies are based on crystalline silicon or thin-film solar cells. Another method of using PV solar energy is concentrated PV (CPV), where sunlight from a larger area is concentrated onto PV cells or modules. PV technology is based on specialized materials releasing electrons and creating direct current (DC) electricity when light energy at certain wavelengths reaches the specialized materials in the cells.

Solar Thermal: A thermal technology that uses reflective materials to concentrate the energy in sunlight onto receivers that collect and convert the energy to heat. This heat is then converted to electricity, usually by introducing pressurized steam into a conventional steam turbine to produce AC power. Utility-scale solar thermal technologies can deliver high electricity output per unit of capacity due to sun tracking and optimization of solar field size and layout. Such solar resource is in abundance in many regions of the world with high electricity demand. Utility-scale solar thermal technologies can be further complemented with on-site storage and are suitable for hybridization with conventional fossil fuels to create a generating asset with more firm and reliable power characteristics than other forms of intermittent energy generation. Solar thermal is frequently referred to as concentrating solar thermal (CST) or concentrating solar power (CSP).

There are two primary solar thermal technologies being pursued today:

•

Power Tower: A system that uses heliostats to track the sun on two axes to concentrate sunlight onto a receiver at the top of a tower to heat a fluid. Power tower systems using our technology use water as the working fluid, which is heated to create high-temperature steam that is then used in a conventional turbine to generate electricity. Some competing technologies use a mixture of molten salts, which, after absorbing heat from concentrated solar energy, produce high-temperature, pressurized steam in a heat exchanger.

•

Parabolic Trough: A system that uses long arrays of single-axis tracking, curved parabolic mirrors to reflect sunlight onto a receiver tube which contains a heat transfer fluid such as oil. The fluid then is passed through a heat exchanger, where heat is transferred from the fluid to water to create pressurized steam. This steam is then used in a conventional turbine to generate electricity.

Parabolic trough systems produce steam at lower temperatures and pressures than power tower systems resulting in a lower solar-to-electricity conversion efficiency and higher costs. There are two additional solar thermal technologies, compact linear fresnel reflector and Stirling dish, neither of which have any projects over 50 MW under construction or in operation. Power tower technology benefits from being both more efficient (mainly because of the higher operating temperature and pressures, reduced parasitic energy use and lower heat losses) and less expensive than other solar thermal technologies.

Solar thermal electric generation has grown significantly in recent decades. Today, there are approximately 1,200 MW of installed solar thermal generation facilities worldwide and approximately 11,000 MW under construction or development. The United States currently has approximately 500 MW of installed capacity, representing roughly 40% of the worldwide total, and is the global leader in capacity under construction or development, representing roughly 60% of the total market. Of the capacity in the United States, approximately 70% was designed and developed by principal members of our technical team.

Enhanced Oil Recovery

Conventional oil recovery methods are only able to extract about 10% to 30% of the original oil from a reservoir, leaving nearly 70% to 90% of the oil in-place. Crude oil development and production can include up to three distinct phases: primary, secondary, and tertiary (or enhanced) recovery. During primary recovery, natural pressure from the reservoir drives oil into the wellbore. This,

combined with artificial lift techniques such as pumping, brings the oil to the surface, but typically only produces about 10% of a reservoir’s original oil in place. Secondary recovery techniques enhance the field’s productive life by injecting water or gases to displace oil and drive it to the wellbore, resulting in the recovery of 20% to 40% of the original oil in-place. However, with much of the easy-to-produce oil already recovered from developed oilfields, producers have attempted several tertiary techniques that offer prospects for ultimately recovering 30% to 60%, or more, of the reservoir’s original oil in place. This tertiary segment is generally referred to as enhanced oil recovery, or EOR.

Many oilfields worldwide have experienced a decline in oil production. Using EOR has the potential to reverse this downward trend and increase worldwide proven reserves by as much as 240 billion barrels of oil, according to SBI Energy. EOR processes are critical to extending the productive life of some of the world’s largest and longest-producing oilfields. In addition, large volumes of proven oil reserves remain unrecovered. EOR technologies are both attractive and feasible, particularly when coupled with rising government interest and investment, rising oil prices, new technologies, and more cost-effective methodologies. According to BCC Research, the global market for EOR technologies was $4.7 billion in 2009 and is expected to grow at a 5-year compound annual growth rate of 28% to $16.3 billion in 2014.

There are currently three commercially viable methods for EOR: thermal recovery, gas injection and chemical injection. According to the DOE, thermal EOR, which principally uses steam, accounts for over 40% of current U.S. EOR production, primarily in California. EOR using solar thermal technology, or solar thermal EOR, has emerged as a highly attractive alternative for steam generation because it significantly reduces emissions and fuel costs.

In addition to EOR, solar thermal technology can provide a supplemental source of steam for existing or new steam systems such as traditional power plants and other industrial process applications.

Our Opportunities

For Utility Applications

As demand for energy grows globally, renewable resources are becoming an increasingly important part of fulfilling that demand. This demand for renewable energy is expected to increase as a result of regulatory policies and incentives put in place to reduce carbon dioxide emissions and improve energy security. For instance, California has recently adopted legislation requiring all California retail energy sellers, including municipal power agencies, to derive 33% of the energy they supply from renewable energy sources by 2020. In addition, recent global events have called into question future energy production from nuclear facilities, which the EIA in 2010 estimated will represent 12.8% of the global electricity generation in 2035. To the extent that production is cancelled or delayed, renewable energy sources will likely be called upon to help bridge the gap. However, increased demand for renewable energy sources is presenting a number of grid integration challenges.

Transmission and distribution of electric power to consumers requires highly complex operating systems. Electricity generation generally must equal electricity consumption at every moment because electricity cannot currently be economically stored. As electricity demand fluctuates throughout the day, the combined output of all available electric generators must continuously be ramped up or down to meet changing demand levels. Among the many measures taken to ensure reliable and consistent electricity supply, utilities and grid operators (operators of electric transmission and distribution infrastructure) in particular require the following:

Sufficient generation capacity available to meet peak demand: Peak demand represents the highest point of electricity consumption during any given period. Over an annual period,

peak demand generally occurs in the afternoon during hot summer days when there is a dramatic increase in the use of cooling equipment, such as air conditioners. Failure to meet peak demand, even for short periods of time can, at its worst, result in rolling blackouts and power outages. Therefore, the grid operator must carry a certain quantity of reserve generation capacity to ensure sufficient availability of power at peak as well as to respond to other reliability needs.

Sufficient flexible power production: As electric demand or supply changes over the course of the day, grid operators must ensure that there are flexible generation resources, such as dispatchable fossil fuel plants, that can vary their production on demand. In general, the production costs of these flexible generation sources are higher than those of baseload power sources, such as coal and nuclear power plants. The addition of renewable resources, which are intermittent and vulnerable to changes in wind and sunlight, creates new requirements for such flexible generation to balance the variable supply of renewable resources.

When procuring renewable energy, one factor utilities consider is power price. Currently, well-sited wind power plants typically can offer a lower price than those of PV or solar thermal. However, this is not the only factor utilities must consider, particularly as renewable energy production increases. Although wind and PV power plants also provide clean energy with low variable costs compared to fossil fuel alternatives, their production characteristics present a number of integration and reliability challenges for utilities and grid operators. Our cost-competitive power tower technology responds to these growing system integration requirements by providing clean energy with characteristics highly valued by utilities, such as reliability and production during peak load hours. While electric power plants using our systems are not yet as reliable as dispatchable fossil fuel plants, they are more reliable and have lower integration costs than highly intermittent renewable technologies such as wind and PV. Furthermore, our system has the potential for thermal energy storage and hybridization, which ease integration within the existing power infrastructure. The ultimate decision regarding whether to implement storage and the level of hybridization in our systems depends on its economic benefits and local and national regulations.

The Grid Integration Challenges and Costs of Utility-Scale Wind and PV

As demand for power continues to grow globally, and renewable energy becomes a larger part of utilities’ resource portfolios, the challenges and costs of integrating renewable resources into the power system have become an important planning consideration. These integration challenges for utilities and grid operators include:

Insufficient generation capacity at peak demand: Demand for power tends to peak daily in the late afternoon or early evening, especially in summer. Wind resources tend to be more consistently available at night, when the demand for power is typically lower than during the day. Production of electricity from solar technologies is better aligned with periods of peak demand. However, neither wind nor PV systems can be counted on to operate at their full capacity at the time of day when demand for power and the price offered to power producers is highest.

Inconsistent power production: Wind turbines or PV installations produce power only during periods of adequate wind resource or sunlight, as applicable. Their output can change suddenly as weather conditions change, causing production to drop quickly and sometimes unexpectedly and then resume just as suddenly and possibly without adequate warning to grid operators. Such characteristics present significant challenges to grid operators and can require procurement of additional expensive, flexible generation reserves.

Lack of economical storage alternatives: While traditional power generation sources can effectively store fuel that can be deployed as needed in the form of electric power, there is

currently no economical way to store energy from wind and PV sources. As a result, absent significant additional expense, wind and PV projects can only produce energy when wind or sunlight is available.

Due to the challenges associated with integrating wind and PV, utilities are adjusting their procurement policies to value the capacity that is delivered by these sources less than power from generation sources with more reliable production at peak periods of demand. Utilities calculate this value using various measures, including an on-peak availability factor, which measures the amount of energy on average that can be delivered at peak hours as a percentage of the generator’s total capacity. Conventional sources of power, such as a combined cycle gas turbine, have on-peak availability factors above 90%, and can be relied upon to generate power when needed and on short notice. The ideal source of renewable power would exhibit similar characteristics to conventional sources of power, without the high fuel costs and negative environmental impacts associated with these technologies. Currently, according to the modeling work prepared for the California Public Utilities Commission by Energy and Environmental Economics, Inc., in California, a wind project on average delivers 16% of its total capacity at peak hours and a fixed-tilt PV project on average delivers 51% of its total capacity at peak hours. In contrast, a solar thermal project on average delivers 77% of its total capacity at peak hours. This percentage will increase with limited hybridization and thermal energy storage. We believe this high on-peak availability combined with the fact that it delivers a more consistent and reliable power source, will drive significant growth for solar thermal technologies.

As utilities incorporate wind and PV into their portfolios, they are also finding that system integration costs increase accordingly. These integration costs include the following elements:

Regulation, also known as regulating reserve: The cost of addressing short-term fluctuations (seconds or minutes) in either supply, such as sudden changes in wind or solar generation, or in demand.

Load following: The cost of procuring dispatchable generation to meet the combined upward and downward fluctuations in demand and wind and solar energy generation.

Unit commitment costs: The cost of starting and stopping conventional generators more frequently in order to address fluctuations in wind and solar production.

Incremental capital investment costs: The cost of retrofitting or building new generation assets to provide support for renewable energy integration into the grid when existing assets cannot provide the required level of support.

These system integration costs, combined with generation and transmission expenses, comprise the total system cost to the utility. This combination of system costs have been rising as more energy is produced from wind and PV resources and as a result, is an increasingly important issue that utilities and regulators consider when evaluating new renewable energy capacity. As discussed in “—Our Technology Solution—For Utility Applications” below, our technology has the capability to reduce these costs and support reliability while providing clean power.

For Thermal EOR Applications

While systems using our technology are primarily used to generate electricity, they can also be used for the production of steam for industrial process applications, such as thermal EOR. EOR is important to the future of oil production, and steam flooding for thermal EOR has proven an effective method of increasing production from heavy oil reserves. Many oil production companies, such as Chevron, Exxon and Shell, are considering the utilization of solar thermal EOR to expand steam generation in order to reduce the emissions and fuel costs associated with fossil fuel steam generation. In addition, many oilfields that could utilize EOR, and specifically solar thermal EOR, are located in

remote locations with limited access to other fossil fuel energy sources. Accordingly, obtaining traditional fuel sources leads to high fuel costs, as well as high operating and maintenance costs, and requires the development of gas or electric infrastructure. Furthermore, many governments now mandate or provide incentives for carbon emissions reductions, such as tax incentives in the form of tax credits and accelerated depreciation.

Our Technology Solution

For Utility Applications

Sufficient generation capacity at peak demand: Our power production profile, or the amount of power our systems produce at different times of the day, can be tailored to the demand profile that most utilities serve. We optimize our solar field layouts and heliostats to maximize energy production at the time of day when power is in greatest demand. Our technology is able to capture the late afternoon sun more efficiently than fixed-tilt PV panels, as our advanced software adjusts each heliostat individually to continue to track the exact position of the sun, even into the early evening. This enables electric power plants using our systems to deliver more power during times of peak demand. We expect that the on-peak availability of Ivanpah will be significantly higher than electric power plants using wind or fixed-tilt PV, on average. Our production profile also enables electric power plants using our systems to receive higher average prices for power. For instance, in some areas, such as California, utilities such as PG&E and SCE are willing to pay contract prices for peak power supply that are as much as three times the base price for each megawatt hour, or MWh, of delivered energy. This significantly enhances the average revenue per MWh that electric power plants using our systems are able to generate compared to wind systems that typically produce power well below their capacity during peak demand periods.

More reliable and consistent power output: Electric power plants using our systems produce more predictable power output than that of highly intermittent renewable sources such as wind and PV. Because our technology converts solar energy into steam, rather than directly into electricity, the system temperature remains high enough to continue to generate electricity through short periods of intermittent cloud cover. Therefore, electric power plants using our systems are less likely to experience sudden and unexpected power output fluctuations. In addition, we expect that electric power plants using our systems will be able to bridge prolonged reductions in solar power output by discharging energy from a thermal energy storage system or by burning small amounts of natural gas, referred to as hybridization. With electric power plants using our systems, utilities and grid operators will require less backup generation compared to competing wind and PV energy sources.

Increased production capability through thermal energy storage and hybridization: In contrast to wind and PV, our technology allows the incorporation of existing cost-effective thermal energy storage and hybridization. This feature can extend the hours of our production period even after the sun goes down, which is particularly important in areas where demand and prices for power remain high later in the day. Shifting electricity generation to critical, peak hours will command higher energy prices (higher average PPA prices) for power plants using our systems. In addition, according to the National Renewable Energy Laboratory, or NREL, thermal energy storage reduces the cost of electricity by increasing capacity factor and increases the total thermal energy production from a solar field. As a result, thermal energy storage can be used to control the daily supply curve of power plants using our technology, reduce system integration costs and increase reliability and consistency. As utilities purchase

greater amounts of electricity from renewable energy sources, we believe the ability to implement energy storage will make our system increasingly valuable to utilities and grid operators. In addition, systems using our technology can be used in combination with traditional fossil fuels such as natural gas, oil and coal, in hybrid generation plants. This hybridization could be operationally very similar to conventional, dispatchable power plants while enabling utilities to save on costs and reduce carbon dioxide emissions during hours when the sun is shining.

As a result of the advantages discussed above, electric power plants using our systems deliver electricity with characteristics highly valued by utilities, such as reliability and flexibility, at a competitive total system cost. In addition, by providing energy during peak demand when utilities are willing to pay the highest price, electric power plants using our systems are able to maximize the revenue realized from the sale of electricity. As the power grid is loaded with increasing quantities of renewable energy over time, we believe that we will have a competitive advantage over other renewable technologies that impose higher integration costs and do not produce electricity as reliably during periods of peak demand.

For Thermal EOR

Our solar-to-steam solution for thermal EOR and other applications associated with oil production is designed to offer oil production and industrial companies a clean, emission-free alternative with the best combination of efficiency, ease of permitting and implementation. Our solar-to-steam solution has several advantages:

Inexpensive to operate due to savings achieved by avoiding the use of fuel to generate steam and very low operations and maintenance expenses.

Simple to integrate with fossil fuel-fired steam generation systems allowing for reduced emissions and fuel cost during the daylight hours and steam generation regardless of the weather or time of day.

Flexible to produce steam not only for EOR but also for electricity to operate the EOR facility or other upstream operations.

Less volatile in total EOR costs through lower exposure to fuel prices.

Well-suited for locations without locally available gas or electricity.

Easier to construct as lower emissions limit the need for expensive permitting and benefit from government incentives and subsidies, which can also apply to the interconnecting infrastructure.

Our power tower technology has the same competitive advantages over other solar thermal technologies for thermal EOR as it does for power generation: lower capital cost, higher efficiency, reduced impact on the environment, and easy adaptation to varying topographical conditions. In addition to these advantages, we believe that the completion of the Coalinga Solar-to-Steam for EOR project in California will provide us with a significant competitive advantage over other solar thermal EOR technologies that have not been proven at large scale. We intend to leverage our solar technology in key regions where there is a combination of good solar resource and oil reserves, such as California and the Middle East.

Our Strengths

We believe that the following competitive strengths position us as a leader within the utility-scale renewable energy market:

Superior technology: We believe our technology represents a compelling solution for utilities seeking superior performance at a competitive cost. The foundation of our technology is

our solar field optimization software and proprietary control system that together optimize the output of energy from our system to match the needs of utilities and maximize project revenue. As a result of our proprietary technology, electric power plants using our systems provide more reliable energy output at peak demand than those of PV or wind. Our system can deliver clean, reliable power that naturally extends late in the day, and can be complemented with thermal energy storage to address peak electricity demands and the need for reliable, consistent power production at a competitive cost. In addition, our system has the capability to augment the electricity production and improve reliability through hybridization with conventional fossil fuels.

Substantial revenue visibility with fully committed, long-term agreements: Through our project companies, we have 13 executed and outstanding PPAs with two of the largest electric utilities in the United States, PG&E and SCE to deliver approximately 2.4 GW of installed capacity. Three of the PPAs are associated with Ivanpah. We retain 10 PPAs to deliver approximately 2.0 GW of installed capacity. We believe these PPAs represent one of the largest utility-scale solar pipelines in the United States and should provide us with a significant revenue opportunity between 2013 and 2016. For purposes of illustration, our agreements for the supply of equipment and services to the Ivanpah project, which has three PPAs totaling 377 MW, represent $672.0 million of contracted sales, which equates to approximately $1.8 million of contracted sales per MW. Consistent with our 14% ownership in Ivanpah, we will recognize 86% of any actual sales as revenue.

Experienced management team: In the energy industry, the experience that comes from years of designing, building and operating utility-scale projects is critical. The principal members of our technical team pioneered the first utility-scale solar energy plant nearly three decades ago by designing and developing 354 MW of solar thermal power plants that remain in operation today. These plants represent approximately 70% of the solar thermal generation capacity currently installed in the United States. Our team has extensive solar thermal technical and project development expertise and has collectively developed, constructed, and managed more than 25 GW of solar, wind and conventional power projects worldwide.

Demonstrated alternative applications of our solar thermal technology: In addition to our electric utility application, our technology provides the oil and gas industry with a clean, emission-free alternative to traditional fossil fuel-based steam generation methods for thermal EOR. Using solar power to produce steam for thermal EOR is particularly attractive in remote areas with limited infrastructure or high fuel costs. EOR and other industrial process applications of our technology diversify our revenue stream and contribute to our future growth.

Strong global partners that support our expansion: We believe our partnerships with leading global companies such as Alstom, Chevron, NRG Solar and Bechtel provide a strong competitive advantage. By leveraging these relationships and our world-class partners’ local expertise in domestic and international markets, we believe we can enter new markets and pursue expansion opportunities more rapidly and cost-effectively than might otherwise be possible. Currently, our key relationships include:

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Alstom: In May 2010, ALSTOM Power Inc. became a stockholder of the Company. In conjunction with this investment, we began business partnership discussions that led to us signing a multi-year business partnership agreement with Alstom in August 2010 to jointly market and bid on projects to design and construct solar thermal power plants in Northern Africa, South Africa and Southern Europe. We subsequently expanded this partnership to include the Middle East and India.

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Chevron: An affiliate of Chevron Corporation made an initial investment in us in 2006. This investment led to business discussions for the use of our systems in a solar-to-steam EOR application. In 2008 we signed an agreement to construct a 29 MWth solar-to-steam EOR facility under a master service agreement with an affiliate of

Chevron. We commenced construction of the Coalinga Solar-to-Steam for EOR project in 2009, and the project began operations in October 2011. We are actively discussing additional thermal EOR deployment and other business opportunities with Chevron.

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NRG Solar: NRG Solar LLC, a subsidiary of NRG Energy, is the lead investor of Ivanpah, investing up to $300 million in the three phases of Ivanpah. NRG Solar is also the operator of Ivanpah.

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Bechtel: We selected Bechtel Power Corporation as the EPC contractor for Ivanpah. In addition, Bechtel participated in the financing for each of the three phases of Ivanpah.

High-quality development site portfolio: To accelerate the development of our systems and satisfy our signed PPAs, we are developing solar thermal projects in the United States. Our rigorous site evaluation and screening process identifies high-quality development sites, and is further enhanced by our extensive regulatory and permitting experience. We have a development site portfolio of approximately 90,000 acres under our control in California and the U.S. Southwest that is well suited for solar power generation. This portfolio has the potential to accommodate approximately 9 GW (gross) of installed capacity. With abundant land, high levels of direct sunlight, geographic proximity to large and growing population centers and strong incentives for renewable power, California and the U.S. Southwest represent some of the most attractive markets for solar thermal applications in the world.

Low impact design: Our systems are designed to have a low impact on the site, limiting changes to topography, soil conditions and vegetation. The heliostats used to focus the sun’s energy on our central tower are mounted on pylons that are driven directly into the ground. Unlike some other renewable energy technologies, such as PV, wind and other competing solar thermal systems, our system greatly reduces the need for concrete pads or extensive land grading. Our systems also cost-effectively use air instead of water to cool steam, which reduces water usage by more than 90% over competing solar thermal technologies that use conventional wet-cooling systems. Given the regulatory restrictions and public concerns for water usage in desert environments, we believe this is an important advantage over other solar thermal technologies that use wet-cooling systems.

Our Growth Strategies

We intend to pursue the following growth strategies to maintain and expand our position as a leader within the utility scale renewable energy market:

Leverage our PPAs into sales of systems using our technology: We intend to use our high-quality development site portfolio to create attractive opportunities for projects where we can sell our solar thermal technology. By executing on these opportunities, we expect to generate substantial revenue, cash flow and profit growth, providing us with the ability to scale and the resources needed to pursue broader growth opportunities.

Develop additional relationships with global industry leaders: We intend to create new relationships with global industry leaders to expand our business. We intend to leverage these new and existing relationships to enter additional markets and pursue expansion opportunities more rapidly and cost-effectively. For example, in February 2012, we and Alstom entered into an agreement with Sasol to conduct a comprehensive front-end engineering and design study for the South Africa market.

Continue to improve our proprietary solar thermal technology: While our systems are currently cost-competitive, we expect our technology roadmap to yield significant cost reductions and a lower total system cost to utilities. We expect improvements to our technology such as higher temperature and pressure operation, software enhancements and larger power blocks, to increase our competitiveness through higher solar energy conversion efficiencies, lower capital costs and increased power production. Our intellectual property portfolio, technical expertise and commitment to research and development have been critical to our success. We intend to continue to lead innovation in solar thermal technology and drive greater capital and operating efficiencies with each new generation of solar power tower technology.

Enhance operating characteristics utilities value most: We recently introduced solar thermal energy storage capabilities and intend to integrate additional features that enhance our system such as hybridization where appropriate. We expect these features to yield a lower total system cost to utilities through greater on-peak availability, higher reliability and increased output.

Our Pipeline Execution and Business Development

Through our project companies that are direct parties to the PPAs, we have 13 executed and out-standing PPAs with two of the largest electric utilities in the United States, PG&E and SCE, to deliver approximately 2.4 GW of installed capacity. We believe these PPAs represent one of the largest utility-scale solar pipelines in the United States and should provide us with a significant revenue opportunity between 2013 and 2016. For purposes of illustration, our agreements for the supply of equipment and services to the Ivanpah project, which has three PPAs totaling 377 MW, represent $672.0 million of contracted sales, which equates to approximately $1.8 million of contracted sales per MW. Consistent with our 14% ownership in Ivanpah, we will recognize 86% of any actual sales as revenue. We attempt to match each signed PPA with a site in our development portfolio that is consistent with and fulfills the requirements of the PPA. Depending on the size of a given site, multiple PPAs can be associated with it. For example, three of the PPAs we signed are associated with Ivanpah. We retain 10 PPAs to deliver approximately 2.0 GW of installed capacity. As part of meeting our obligations under these 10 PPAs, we have a robust development site portfolio comprised of approximately 90,000 acres of land under our control across California and the U.S. Southwest. This site portfolio has the potential to accommodate approximately 9 GW (gross) of installed capacity.

There are several key phases of the site development process including the identification, design, permitting, financing, construction and placement into commercial operation of each project. For the projects where we lead development, we expect to own initially 100% of the equity in the projects but may seek development partners on specific projects. A project’s assets are typically held by a special purpose, single member limited liability company, in which we are initially the sole member, that we refer to as a project company. We intend to ultimately transfer the majority of the equity in each project company to third parties while retaining a minority equity interest. Until the time of such transfer, we expect to wholly own each project company and consolidate its profits and losses.

Ivanpah, the first project that will deliver power to serve PPAs that we have signed, is comprised of three concentrating solar thermal power plants. This project combines attractive solar conditions with readily available access to electric transmission, water and natural gas access. Ivanpah is located on an approximately 3,500 acre site in California’s Mojave Desert and will have an installed capacity of 377 MW.

While our engineering team is actively engaged in the technical design of Ivanpah, Bechtel is leading its construction and NRG Solar will manage its operation. We have guaranteed all obligations of our subsidiaries that have entered agreements to provide solar field systems and services for each of three phases of Ivanpah. We are also required to fund an escrow of approximately $108.6 million by April 2012 to secure potential construction delay and performance damage payments or warranty liabilities under these solar field system and service agreements.

All three Ivanpah phases have fully committed equity and debt financing of approximately $2.2 billion to fund construction costs, together with other project costs such as interest during construction, sales tax, mitigation and development costs, interconnection costs, cost contingencies and debt reserves. Ivanpah received a $1.6 billion loan, guaranteed by the U.S. Department of Energy and funded by the Federal Financing Bank, a branch of the U.S. Treasury. In addition, Ivanpah has received a total equity commitment of $598 million, consisting of $300 million from the lead equity investor, NRG Solar, $168 million from Google, and $130 million from us. A portion of our equity commitment was funded by a $20 million loan from Bechtel. Our ongoing obligations related to Ivanpah, including solar field guarantees and cost overrun funding, are described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Post-Ivanpah Closing Contractual Obligations.”

We currently have three sites in advanced development, Rio Mesa Solar and Hidden Hills Ranch, each located in California, and Sandy Valley, located in Nevada. Rio Mesa Solar consists of approximately 5,800 acres, Hidden Hills Ranch consists of approximately 3,300 acres, and Sandy Valley consists of approximately 10,000 acres. In August and October 2011, we filed Applications for Certification with the California Energy Commission for the development of two 250 MW solar power plants at Hidden Hills Ranch and three 250 MW solar power plants at Rio Mesa Solar, respectively. In October 2011, the California Energy Commission found our Hidden Hills Ranch Application for Certification to be data adequate. If approved, construction of the plants is expected to be complete in 2014 and 2015. The electricity generated by the two plants at Hidden Hills Ranch and by two plants at Rio Mesa Solar will be sold to PG&E and SCE, respectively, pursuant to four of the 10 PPAs. The third proposed plant at Rio Mesa Solar is currently unassigned and can be used to satisfy one of our existing PPAs or a future PPA. In January 2012, we entered into two master service agreements for engineering and home office services for Hidden Hills Ranch and Rio Mesa Solar. We are developing the other sites in our 90,000 acre portfolio and working to identify new sites with attractive characteristics for utility-scale solar thermal power plants. In addition, we are actively working to secure additional PPAs, which we intend to match with sites in our portfolio.

In addition to executing on our existing pipeline of PPAs we are focused on identifying additional opportunities to sell our systems in targeted international and domestic markets. We are partnering with Alstom on bids for projects in international markets, such as the Middle East, Northern Africa, South Africa, Southern Europe and India. For example, in March 2011, we jointly submitted a bid with Alstom in response to a tender process conducted by the State of Israel for a 110 MW solar thermal power plant near Ashalim, Israel. In September 2011, the tender committee advised us that the bid has passed the minimum threshold requirements but has been provisionally rejected due to the pricing. The committee has indicated that it expects to invite us to meet with it to discuss certain issues relating to the bid. We also intend to pursue additional opportunities for the development of large scale thermal EOR projects using our systems globally. Our Coalinga Solar-to-Steam for EOR project in California developed in partnership with Chevron represents our first thermal EOR project and is expected to commence operations in the second half of 2011. We believe that solar-to-steam applications of our systems, such as thermal EOR, represent a significant growth opportunity.

While Ivanpah has fully committed financing, executing on our pipeline and expanding our business requires significant additional capital. Once Ivanpah and the Coalinga Solar-to-Steam for EOR project are operational, we expect to be able to access the traditional project finance and capital markets to both develop and construct future projects.

Our Technology

Our proprietary solar-to-steam system integrates with conventional power block components to deliver cost-competitive, reliable and clean power to utilities when needed most. Our system utilizes fields of heliostats controlled by our proprietary software to concentrate sunlight onto a solar receiver/boiler unit to produce high-temperature steam. This high-temperature steam can be used in the production of electricity or for solar-to-steam applications such as thermal EOR. Our heliostats are strategically arranged around a central tower using our proprietary solar field optimization algorithms

that position the heliostats to maximize project-specific revenue generation. The solar receiver is a utility-scale boiler, designed to be heated from the outside using concentrated solar radiation reflected onto the boiler by the heliostats. From the solar receiver, high-temperature, pressurized steam is then piped to a conventional steam turbine generator that produces electricity. The electricity is delivered to utility customers through a connection to the transmission grid. The steam is air-cooled and piped back into the feedwater loop through a process that uses significantly less water than solar thermal plants that use wet-cooling systems.

The diagram below shows the key components of a solar thermal power plant using our system.

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The foundation of our technology is our solar field optimization software and proprietary control system that together maximize energy output from our system to match the needs of utilities and industrial process companies. Other key components of our system include heliostats and a solar receiver.

Solar Field Optimization Software

Our proprietary solar field optimization software is used during the system design phase to determine the optimal position of each heliostat to achieve each customer’s power production profile. The software runs comprehensive simulations of year-round operation based on actual site conditions (including physical obstacles and no-build zones) combined with custom-built meteorological datasets, and produces precise GPS-ready mappings ready for download to solar field installation crews. This technology provides considerable design flexibility in supporting irregular site footprints and topographies, allowing projects to be built on sites of nearly any geometric shape.

Control System

Our advanced proprietary software system, the Solar Field Integrated Control System, or SFINCS, controls the heliostats arrayed in the solar field to track the sun. SFINCS performs a number of functions including:

Solar energy management, to focus the ideal amount of solar energy on the receiver at various times of the day to maximize electricity production while ensuring that the solar receiver’s flux and temperature limits are not exceeded.

Solar field control, to provide aiming points on the solar receiver surface for each individual heliostat, as well as facilitating start-up and shutdown.

Heliostat tracking maintenance, to calibrate the heliostats based on three-dimensional laser scanning and other photogrammetric methods.

At the core of the SFINCS are our proprietary algorithms that perform real-time optimization of the distribution of energy across our solar receiver using real-time, heliostat-aiming and closed-loop feedback systems. In addition, SFINCS can automatically configure the heliostats to protect them from inclement weather and other stresses.

Heliostats

Our tracking mirrors, known as heliostats, are highly engineered and designed for accuracy, durability and longevity with minimal maintenance. Our current generation heliostat consists of two flat, low-iron, float-glass mirrors, each borne by a lightweight steel support structure, mounted on a single pylon that also features a computer-controlled drive system that enables the heliostat to track the sun to an aiming point on the solar receiver. In the current system design, a 130 MW plant will utilize up to 60,000 heliostats, depending on land area and shape, and site-specific economic optimization. The low-impact design of the heliostat allows our sites to include a slope of up to 5%, and avoids most of the costs of leveling and grading a site. Moreover, most desert vegetation can remain undisturbed, which is particularly important in environmentally sensitive areas.

Heliostats, front and back views

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Solar Receiver (Boiler)

The solar receiver is a utility-scale industrial boiler designed to be heated from the outside using concentrated solar radiation reflected onto the boiler by the heliostats. The current design for use in our projects is that of a standard forced-recirculation, drum-type boiler with superheater and reheater. Our solar receiver is designed and manufactured to our specifications by qualified boiler manufacturers. The boiler is designed to withstand the rigors of the daily cycling required in a solar power plant over the course of its lifetime, and is treated with a proprietary solar-absorptive coating to ensure that maximal solar energy is absorbed in the steam.

In electricity generation applications, the high-temperature, pressurized steam generated in the solar receiver is piped to a conventional steam turbine generator. The electricity generated is then delivered to the transmission grid for consumption. The steam is air-cooled and recirculated. By using dry cooling, we believe our system consumes over 90% less water when compared to a similar plant using a wet-cooling system. We believe this process represents an important design element of our system since projects using our systems are likely to be located in arid or desert locations.

In a solar-to-steam application, such as thermal EOR, the process is generally the same as for generating electricity. However, for solar-to-steam applications, saturated steam is piped from the receiver, which typically will not have a superheater, to a heat exchanger to generate the process steam. Solar-to-steam applications frequently require lower temperatures and pressures compared to electricity generation.

Hybridization

Our system design allows for integration with natural gas or other fossil fuels, referred to as hybridization, to enable increased output and more reliable production of electricity. There are three levels of hybridization as described below. The decision to integrate hybridization in our systems, and at what level, is made on a project-by-project basis depending on analysis of the net economic impact to the project, and to the utility’s power grid, and local and national regulations. For example, California’s Renewable Portfolio Standard applies a cap to the amount of energy that can be produced by qualifying renewable resources through co-firing of fossil fuels, which resulted in an optimal design selection of hybridization for supplemental production at Ivanpah. For future projects, we may choose to increase the level of hybridization subject to specific project contracts and regulations.

Hybridization for Supplemental Production: We use a minimal amount of natural gas, in accordance with national and local regulations, to improve the reliability of electricity production throughout the day. For example, each of the three Ivanpah plants will be equipped with a small auxiliary gas-fired boiler that assists with daily start-up, provides steam during short periods of cloud cover, and produces additional electricity when solar radiation declines during the late afternoon. These small boilers will typically be called upon to produce the equivalent of 2% to 5% of the total electricity output of each project.

Hybridization for Extended Production: We are currently engineering our projects in advanced development with larger gas-fired boilers that can provide as much as 50% of a plant’s power rating. In addition to adding reliability (to an even greater degree than the smaller boilers at Ivanpah), these boilers can provide higher on-peak availability, and add dispatchability capabilities that can help utilities and grid operators avoid having to invest in other, more expensive solutions to ensure long-term reliability and operational flexibility, such as construction and operation of additional gas turbines. The boilers are planned to produce at least 5% of each project’s annual electricity production, and in some cases could be used to produce an additional 5% to 10% of the plant’s annual electricity production when deployed as dispatchable capacity.

Complete Hybridization: In some markets, particularly outside the United States, it is possible to use our technology to produce steam in conjunction with natural gas or other fossil fuels to produce electricity. This allows a power plant to operate as a baseload power source while significantly reducing levels of air pollutants and other regulated emissions.

Storage

Our solar power tower technology has the capability to use existing cost-effective thermal energy storage in the form of molten salts to augment electricity production late in the day, improve the reliability of electricity delivery, shape our daily power supply curve and potentially serve the market for services such as regulating reserve and load following. Storage also allows electric power plants using

our systems to supply electricity for more hours per year and shift electricity generation to critical hours with higher energy prices. Our technology roadmap includes the development of a solution to deliver up to six hours per day of molten salt storage. We recently announced the launch of a new solar thermal plant solution called SolarPLUS, which combines our solar power tower technology with two-tank molten-salt storage capabilities. In such a system, heat from excess steam is stored in a blend of molten nitrate salts (sodium nitrate and potassium nitrate) until the storage system is discharged by reversing the flow of the system and steam is generated from the heat stored in the salts. In October 2011, we executed amendments to five PPAs, three of which provide for the utilization of our SolarPLUS solar thermal plant solution.

Solar Energy Development Center

In June 2008, we opened the Solar Energy Development Center, or SEDC, a fully operational 6 MWth demonstration solar-to-steam facility used to test equipment, materials and procedures as well as construction and operating methods. The SEDC is a scaled cross-section of a typical commercial plant and serves to demonstrate the same proprietary technology that will be used for utility-scale projects that use our technology. An independent engineering firm tested and verified the SEDC’s ability to produce high-temperature and high-pressure solar steam, which we believe are the world’s highest. In a full-sized commercial plant, this utility-grade superheated steam is piped from the boiler to a standard turbine to generate electricity. The SEDC power tower and surrounding heliostats concentrate the sun’s energy onto the boiler, heating the water inside up to 540°C, or more than 1,000°F. The SEDC plant includes more than 1,600 heliostats and a 60 meter tower topped by a solar boiler. The SEDC is located in the Rotem Industrial Park in Israel’s Negev Desert, about 100 km (60 miles) southeast of Jerusalem.

Suppliers

We generally obtain components for our solar thermal systems from multiple suppliers. Because of lead times, we currently source some of our key components for Ivanpah from a limited or sole source of supply, including boilers from Riley Power and turbines from Siemens.

Customers

We sell our systems into utility-scale solar thermal power projects either directly to project owners or indirectly as a sub-supplier to the contractor providing engineering, procurement and construction services to project owners. In conjunction with these sales, we provide technical services related to the design, engineering and operation of our systems. We also sell our systems and technology to oil production companies pursuing thermal EOR activities. In 2011, Ivanpah and Chevron represented the vast majority of our revenue.

Power Purchase Agreements (PPAs)

Power purchase agreements are contracts that provide for the purchase of power at an agreed-upon price for a period of time, which is typically 20 to 25 years for solar projects. Through our project companies, we have 13 executed and outstanding PPAs to deliver approximately 2.4 GW of installed capacity with two of the largest electric utilities in the United States. Ivanpah will fulfill the commitments under two of the PG&E PPAs and one of the SCE PPAs, and we retain 10 PPAs to deliver approximately 2.0 GW of installed capacity.

We believe these PPAs constitute one of the largest utility-scale solar pipelines in the United States.

Pacific Gas and Electric Company (PG&E): In April 2008, we entered into five PPAs with PG&E to deliver 900 MW of installed capacity. In April 2009, we signed two additional PPAs with PG&E, increasing the total contracted installed capacity to 1,310 MW. All seven PPAs

have been approved by the California Public Utilities Commission, or CPUC. Two of the PPAs have been assigned to Ivanpah, and the contracted capacity under the remaining five PPAs is now 1,000 MW. Each PPA provides that PG&E will purchase the full output of an individual power plant for a period of 25 years, and specifies a commercial operation date, or COD, for the power plant (the earliest in 2013, and the latest in 2017). Based in San Francisco, California, PG&E is one of the largest electric utilities in the United States, serving approximately 15 million customers in Northern and Central California.

Southern California Edison (SCE): In February 2009, we entered into seven PPAs with SCE to deliver 1,300 MW of installed capacity, one of which was assigned to Ivanpah. In October 2011, we amended and restated five of the PPAs to deliver 1,000 MW of installed capacity. These PPAs were submitted to the CPUC for approval in November 2011. In conjunction with these amendments, the one remaining PPA was consolidated such that the combined expected annual energy production of the five remaining PPAs approximates the combined expected annual energy production of the original six PPAs. Three of the five PPAs provide for utilization of our SolarPLUS solar thermal power plant solution. Each PPA provides that SCE will purchase the full output of an individual power plant for a period of 20 years, and specifies COD for the power plant (the earliest in 2015, and the latest in 2017). SCE is one of the largest electric utilities in the United States, serving nearly 14 million customers in Central, Coastal and Southern California.

Research and Development

We engage in extensive research and development efforts to improve solar efficiency and reduce system costs and complexity to maintain our competitive advantage. Our research and development organization, consisting of approximately 220 employees located in Israel, works closely with our third- party equipment and service providers and our customers to improve our solar thermal technology and reduce costs. Our research and development expenditures were approximately $16.6 million in 2008, $9.7 million in 2009 and $8.6 million in 2010.

Intellectual Property

We have developed our own proprietary intellectual property relating to the design, construction and operation of our solar thermal technology and systems. We primarily rely on trade secret and contractual rights, including confidentiality and nondisclosure agreements, to protect our proprietary information and know-how. We also maintain a growing patent portfolio that currently consists of nine issued U.S. patents (including one patent covering dynamic system optimization and another covering integration of solar thermal systems and PV, both of which were issued by the U.S. Patent and Trademark Office in the second half of 2011, and one patent covering heliostat and receiver design), Which expire between January 2023 and August 2028. We also maintain numerous patent applications, including 11 patent applications covering control systems and solar field optimization software, five patent applications covering our operating methods, six patent applications covering heliostat and receiver design, and three patent applications covering thermal energy storage. Our patent strategy is to invest the resources necessary to protect our value-added development and to obtain, to the extent possible, broad and meaningful patent coverage for systems using our technology.

Competition

We compete in the utility-scale power and thermal EOR markets. Within the utility-scale power market, we believe that our principal competitors are companies developing renewable energy solutions, such as solar thermal, PV (such as crystalline silicon, thin film and CPV) and wind technologies. In addition, we compete with companies using conventional fossil fuels to generate electricity. Within the utility-scale renewable energy market, the principal factors upon which we compete are:

total system cost to utility (including power price and system integration cost)

efficiency (energy output)

reliability (delivering power on a continuous basis throughout the day and into peak hours)

operational flexibility (including performance and peak demand availability)

We believe we compete favorably on each of these factors.

Within the EOR market, we compete with companies utilizing thermal recovery processes. Within the thermal EOR market, the principal factors upon which we compete are price, performance and environmental attributes.

Many of our competitors within the broader energy and renewable energy sector have longer operating histories and significantly greater financial and other resources than we do. These competitors may be able to respond more quickly to new or emerging technologies and changes in customer requirements and to devote greater resources to the development, promotion and sale of their products than us. In addition, we expect to compete with future entrants to the solar thermal industry that offer new technological solutions.

Regulatory Matters

In the United States, our project companies and third-party projects that use our solar thermal technology are subject to extensive regulation by various federal, state and local government agencies. The federal government regulates the wholesale sale and transmission of electric power in interstate commerce through the Federal Energy Regulatory Commission, or FERC, and regulates environmental matters through a variety of agencies. States and local governments regulate the construction of electricity generation, steam generation and electricity transmission facilities, the intrastate distribution of electricity, retail electricity sales and certain environmental matters through various agencies. Similar national, regional and local regulatory frameworks apply in other countries, and multinational confederation frameworks may also apply, as in the European Union. Our project companies located in other countries would be required to comply with the energy, environmental and permitting requirements to the locations in which the projects are located.

U.S. Federal Regulation

Our project companies for electricity generation projects qualify as exempt wholesale generators, or EWGs, through the self-certification procedures contained in FERC regulations. EWGs are entities that engage exclusively in the business of owning generating facilities selling the resulting electric energy products in wholesale markets, and thus qualify for exemption from FERC’s books and records regulations under the Public Utility Holding Company Act of 2005. Our electricity generation project companies will sell electric capacity, energy and ancillary services at market-based rates upon application for, and receipt of, authority granted by FERC.

Our electricity generation project companies are also subject to the reliability standards and operating procedures of the North American Electric Reliability Corporation, or NERC. If our project companies fail to comply with the mandatory reliability standards (either national or the regional and local requirements noted below), our project companies could be subject to sanctions, including substantial monetary penalties.

Due to the height of some of our solar power towers and their potential effect on aviation, our project companies are also required under certain circumstances to seek approval from the Federal Aviation Administration and/or to consult with the Department of Defense.

U.S. Regional and State Regulation

In addition to the reliability requirements of the NERC, our electricity generation project companies are required to comply with the regional reliability requirements of the Western Electricity Coordinating Council, or WECC, as well as standards that may be applied by other balancing area authorities in which our projects may be located, such as those of the California Independent System Operator Corporation, or CAISO. If our electricity generation project companies fail to comply with the mandatory reliability standards, our project companies could be subject to sanctions, including substantial monetary penalties.

The California Energy Commission is responsible for permitting the construction and operation of certain electric power plants located in California, including those using our systems, and provides comprehensive certification of such projects, which include all state environmental permits. Furthermore, county building permits and separate environmental permits are required for solar-to-steam projects in California. Projects outside California may require building permits and separate environmental permits, including for air emissions and any potential impact on wildlife species.

State public utilities commissions, such as the CPUC, the Public Utilities Commission of Nevada and the Arizona Corporation Commission regulate public utility companies operating in their respective states and establish rates, tariffs, charges and fees, as well approve power purchase agreements between our electricity generation project companies and utilities under their jurisdiction. These commissions are generally responsible for overseeing the renewables procurement obligations. These commissions are also responsible for permitting the construction of transmission within their respective states; while in California this jurisdiction is exclusive, in other states, such as Nevada, local approvals may also be required.

Environmental Regulation

Our project companies are subject to various environmental, health and safety laws and regulations in each of the jurisdictions in which they operate. These laws and regulations require our project companies to obtain and maintain permits and approvals, undergo environmental review processes and implement environmental, health and safety programs and procedures to control risks associated with the siting, construction, operation and decommissioning of their projects, all of which involve a significant investment of time and expense.

Under U.S. laws and regulations such as the Federal Clean Air Act, Federal Clean Water Act, National Environmental Policy Act and endangered species requirements, U.S. Bureau of Land Management, or BLM, requirements and other state and local programs, our project companies are required to obtain a range of environmental permits and other approvals from federal, state and local governmental authorities to build and operate the projects. For example, the activities of our project companies are regulated by various federal environmental and natural resource agencies including the U.S. Army Corps of Engineers (on wetland and certain water issues); the U.S. Environmental Protection Agency, or EPA, (on air quality, storm water, wetland and certain other issues); the U.S. Fish and Wildlife Service (on wildlife species issues); and the BLM (in relation to its management of federal lands on which our sites may be located, or through which generator tie-lines may transverse). Our project companies incur costs in the ordinary course of business to comply with these laws, regulations and permit requirements. Failure to comply with these laws, regulations and permit requirements may result in administrative, civil and criminal penalties, imposition of investigatory, cleanup and site restoration costs and liens, denial or revocation of permits or other authorizations and issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property have been brought and may in the future result from environmental and other impacts of their activities.

Governmental Programs and Incentives

One of the key factors contributing to the growth of solar power and other sources of renewable energy in the United States is the existence of several government incentive programs and regulatory requirements at both the state and federal level.

Renewable Portfolio Standards

A Renewable Portfolio Standard, or RPS (sometimes called a Renewable Energy Standard, or RES), is a program mandating that a specified percentage of electricity sales in a state or municipality originate from eligible sources of renewable energy. In the United States, over half of the states, including our initial target markets in California and the U.S. Southwest, have implemented ambitious RPS programs that require retail electricity suppliers to provide a minimum percentage of their retail supply from eligible sources of renewable energy. State RPS requirements have been a major driver of renewable energy growth in the United States. Of the 30 GW of non-hydro renewable capacity added since 2004, 90% has been built in states with established, legally binding RPS requirements, according to Emerging Energy Research. State climate change programs, such as California’s Global Warming Solutions Act (known as AB 32), provide both RPS requirements for electricity, which help create the market for electric power plants using our systems, as well as carbon-reduction requirements for other sectors, which facilitate a market for our solar-to-steam projects.

In addition to state RPS programs, federal legislation to establish a national clean and/or renewable energy standard remains in consideration. Several such bills have been introduced in the House and Senate in recent years and there has been an increasing discussion of a Clean Energy Standard, or CES, which would include renewables along with other low- or no-carbon energy sources, such as hydro, clean coal and nuclear. Interstate electrical transmission planning to support the timely development of renewable energy projects has been a central focus of proposed federal legislation and FERC rules. Federal and state regulators are working together to implement renewable generation and transmission, and will need to increase their efforts in the event of adoption of a federal renewables generation program and/or a federal program for renewable transmission.

California and the U.S. Southwest states that our project companies are targeting have mandatory RPS policies and in some cases, specific set-asides for solar projects. California has recently adopted legislation requiring all California retail energy sellers, including municipal power agencies, to derive 33% of the energy they supply from renewable energy resources by 2020. In the U.S. Southwest, Nevada’s RPS requires 25% of total electric generation to come from eligible sources of renewable energy by 2025, Arizona’s RPS requires 15% by 2025, and New Mexico requires 20% by 2020 for investor-owned utilities and 10% by 2020 for utility cooperatives. Given this region’s energy needs, demand characteristics and renewable energy resources, we believe that the majority of the electrical power supplied from renewable energy projects built in response to RPS mandates in this region will be in the form of solar energy. In addition to RPS programs, some states have technology-specific requirements, such as New Mexico’s mandate that a minimum of 20% of the total RPS requirement applicable to investor-owned utilities must come from solar energy sources (i.e., 4% of retail sales must be from solar energy resources). The RPS programs and supplemental requirements in these states require additional renewable energy development in order for the RPS program requirements to be achieved, and thus present significant growth opportunities for solar power development.

Federal Tax and Economic Incentives

Since 2008, the U.S. Government federal stimulus legislation has included multiple elements that significantly encourage investment in the renewable energy sector, promote the development of domestic green-collar jobs and act as an engine of economic growth. The American Recovery and Reinvestment Act of 2009, or the ARRA, includes over $80 billion in incentives to encourage

investment in the renewable energy sector. President Obama has demonstrated consistent support for growing the renewable energy industry including, most recently, the 2011 State of the Union address in which he stated his intent to pursue a Clean Energy Standard and established the goal of obtaining 80% of U.S. electricity from clean energy sources by 2035.

Extensive U.S. Government support creates compelling incentives for companies to finance and build new utility-scale renewable energy projects in the United States. Even prior to passage of the ARRA, the federal government enacted several major incentives that support solar development. Certain of these initiatives include:

Investment tax credits: Increasing the investment tax credit for solar energy projects from 10% to 30% and extending it through December 2016.

Accelerated depreciation: Allowing accelerated depreciation of capital costs over five years for solar projects placed in service after 1986.

DOE loan guarantee program: Providing DOE Title XVII loan guarantees of up to 80% of the cost of a renewable energy project that utilizes new technology, and in some circumstances, providing direct loans funded by the Federal Financing Bank, as in the case of Ivanpah.

In 2009, the ARRA added a number of meaningful incentives that encourage investment in solar energy, including the following:

Cash grants in lieu of tax credits: Developers have the option to forego the investment tax credit and elect to receive a cash grant from the U.S. Treasury for 30% of the project cost for solar projects that are under construction by the end of 2010. In December 2010, Congress extended this commencement deadline to the end of 2011.

Bonus depreciation: The ability to claim an additional depreciation deduction equal to 50% of the capital expenditures of a project immediately for projects completed during 2009 and on some equipment installed in 2010. In December 2010, Congress extended this program to allow eligible property placed in service after September 8, 2010 and before January 1, 2012 to qualify for 100% first-year bonus depreciation. For 2012, bonus depreciation is still available, but the allowable deduction reverts from 100% to 50% of the eligible basis.

DOE loan guarantee expansion: Six billion-dollar expansion of the DOE loan guarantee program cost, with a streamlined application process, lower credit subsidy charges and a broader mandate to fund energy projects. Although the ARRA expanded the DOE loan guarantee program to $6 billion and was estimated to provide at least $60 to $80 billion of financing for the industry, funding for this program has been substantially reduced to $2.5 billion and continues to face challenges. As a result, the program may not continue past the projects already financed such as Ivanpah. We were one of the technology companies selected for the DOE’s Title XVII loan guarantee program, and the only solar thermal technology company included in the first phase of that program. As part of the program, Ivanpah received a $1.6 billion loan, guaranteed by the DOE and funded by the Federal Financing Bank, a branch of the U.S. Treasury, which closed in April 2011.

Employees

As of December 31, 2011, we employed 363 full-time employees and 47 part-time employees, including 277 engaged primarily in research, development and operations activities, and 133 in administrative activities. Of these employees, 116 full-time employees are located in the United States, primarily in Oakland, California, and 247 full-time and 46 part-time employees are located outside the United States, primarily in Jerusalem, Israel. As of December 31, 2011, we also employed (directly or

through third-party agencies) 35 individuals on a contract basis (29 on a full-time basis), 18 of whom were primarily engaged in research, development and operations activities. None of our employees are represented by a labor union, and we consider our employee relations to be good.

Legal Proceedings

On January 13, 2011, the La Cuna De Aztlan Sacred Sites Protection Circle Advisory Committee, Californians for Renewable Energy, and seven individuals filed a complaint in the United States District Court, Central District of California, alleging that the permitting process for the four large scale solar projects on federal land in California subject to that court’s jurisdiction, including Ivanpah, did not comply with various federal requirements. The original complaint named the U.S. Department of Interior, or DOI, the project companies holding permits for Ivanpah and permit-holding developers of other projects as defendants. The complaint was amended on August 5, 2011 to add new defendants, including the DOE, Federal Financing Bank and U.S. Treasury Department, and to add additional claims. The complaint seeks injunctive relief, but no motion for injunctive relief has been filed in the suit against Ivanpah. A summary judgment hearing is scheduled for August 2012 and trial on any remaining issues is to begin in January 2013.

On January 14, 2011, the Western Watersheds Project filed a complaint in the United States District Court, Central District of California, against the DOI also alleging that the permitting process for Ivanpah did not comply with various federal requirements. Subsequently, we intervened as a defendant in the case. On August 10, 2011, the District Court denied a preliminary injunction motion filed by the Western Watersheds Project, which plaintiff appealed to the Ninth Circuit Court of Appeals. On August 30, 2011, the Ninth Circuit denied plaintiff’s request for an injunction pending appeal. A summary judgment hearing was held in January 2012.

We believe the lawsuits will not succeed on the merits, and that the likelihood of an injunction materially impairing the project is increasingly small with the passage of time. Nonetheless, litigation, whether or not determined in our favor, can be costly and time consuming and could divert our attention and resources, which could adversely affect our business.

We are not currently a party to any other material litigation. Our industry is subject to extensive and rapidly changing federal, state and local electricity, environmental, health and safety and other laws and regulations. We may from time to time become subject to legal proceedings and claims that arise in the ordinary course of business, including proceedings contesting our permits or the construction or operation of our projects.

Facilities

Our principal executive offices are located in Oakland, California, where we lease approximately 30,000 square feet under leases that expire in December 2013 and June 2014. In addition, we lease approximately 15,000 square feet in Jerusalem, Israel, for our research and development organization under three leases that expire between May 2012 and December 2015 and approximately 236,000 square feet of demonstration facility and test site space under two leases, the terms of which are currently being extended. We also lease space (typically less than 2,000 square feet) in various geographic locations primarily for sales and support personnel. We believe that our current facilities are adequate to meet our needs through the middle of 2014, at which time we may need to lease additional space.

We have an approximately 90,000 acre development site portfolio under our control in California and the U.S. Southwest. The development site portfolio is comprised of land in which we, directly or through our project companies, hold options to lease (private land), leasehold interests and rights to lease (public land), including “right-of-way” grants from the BLM. We do not currently own or lease any land that we consider to be materially important physical properties.

MANAGEMENT

Executive Officers and Directors

The names and ages of our executive officers and directors as of December 31, 2011 are as follows:


Name	Age		Position(s)
John M. Woolard		46	President, Chief Executive Officer and Director
John “Jack” F. Jenkins-Stark		60	Chief Financial Officer
Israel Kroizer		59	Executive Vice President of Engineering, R&D and Product Supply
Joseph F. Desmond		47	Senior Vice President of Government Affairs and Communication
Arnold J. Goldman		68	Chairman Emeritus, Founder and Director
Daniel T. Judge		48	General Counsel and Corporate Secretary
Lynda Ward Pierce		48	Senior Vice President, Human Resources and Administration
Stephen A. Wiley		51	Senior Vice President of U.S. Project Development
Nicholas E. Brathwaite(2)		53	Director
Denis Cochet		58	Director
J. Stephan Dolezalek(2)		55	Director
James Eats(1)(2)		53	Director
David C. Fries(3)		67	Director
Richard C. Kelly(1)(3)		65	Chairman of the Board
Thomas M. O’Flynn(1)(3)		51	Director

(1)	Member of Audit Committee

(2)	Member of Compensation Committee

(3)	Member of Nominating and Governance Committee

John M. Woolard has served as our President and Chief Executive Officer and a member of the board of directors since October 2006. Prior to joining BrightSource, Mr. Woolard was an Executive-in-Residence at VantagePoint Capital Partners’ CleanTech Group from 2005 to 2006. From 2003 to 2005, Mr. Woolard served as Vice President of Software Solutions and subsequently the Vice President of Strategy and Business Development at Itron, Inc., which in 2003 acquired Silicon Energy Corporation, an energy management software company. Mr. Woolard co-founded Silicon Energy Corporation and was President, Chief Executive Officer and Chairman of its board of directors from 1997 to 2003. Mr. Woolard has previously held positions with Lawrence Berkeley National Labs and PG&E. Mr. Woolard is a Crown Fellow at the Aspen Institute, and he currently serves on the advisory boards of the Tuolumne River Preservation Trust and University of California, Berkeley’s Haas School of Business Energy Institute and Lester Center for Entrepreneurship. Mr. Woolard holds an M.B.A. from the Haas School of Business at the University of California, Berkeley, a Masters in Environmental Planning from the University of Virginia, and a B.A. in Economics from the University of Virginia. Mr. Woolard brings to our board of directors nearly two decades of experience in the energy technology sector as an executive, entrepreneur and investor.

John “Jack” F. Jenkins-Stark has served as our Chief Financial Officer since May 2007. From May 2004 to May 2007, Mr. Jenkins-Stark served as Chief Financial Officer at SVB Financial Group. He previously served as Vice President of Business Operations and Technology at Itron and as Senior Vice President and Chief Financial Officer at Silicon Energy from 2000 to 2004. He also served as Senior Vice President and Chief Financial Officer of GATX Capital from 1998 to 2000 and held senior

management roles at PG&E Corporation from 1988 to 1998. He serves on the board of directors of the general partner of TC PipeLines L.P., a publicly-traded energy infrastructure business. Mr. Jenkins-Stark holds both a Bachelor’s and Masters degree in Economics from the University of California, Santa Barbara and an M.B.A. from the Haas School of Business at the University of California, Berkeley. Mr. Jenkins-Stark brings more than three decades of energy industry and finance experience to BrightSource.

Israel Kroizer has served as our Executive Vice President of Engineering, R&D and Product Supply since May 2011, prior to which he served as our Chief Operating Officer since November 2007, and as our Vice President of Israeli Operations from October 2006 to November 2009. He has served as President of BrightSource Industries, (Israel) Ltd. (formerly named Luz II Ltd.), or BSII, since October 2006. From 1987 to 1991, Mr. Kroizer served as the Senior Vice President of Luz International Ltd. and the President and CEO of Luz Industries (Israel) Ltd., where he was responsible for the original Luz International thermal design and for the management of more than 500 research and development staff. Between 1994 and 2006, he was the owner of Israel Kroizer Ltd., which developed energy and water projects for municipalities, major industrial clients and banks. Mr. Kroizer holds a B.S. and a Masters in Mechanical Engineering, specializing in energy, from the Technion in Haifa, Israel. Mr. Kroizer is a world-renowned expert in solar power generation technology.

Joseph F. Desmond has served as our Senior Vice President of Government Affairs and Communications since August 2011. Prior to joining BrightSource, Mr. Desmond served as Executive Vice President and Chief Marketing & Business Development Officer of Ice Energy, Inc., a provider of intelligent energy storage solutions to the utility industry, from August 2010 to August 2011. From November 2006 to May 2010, Mr. Desmond served as the Senior Vice President, External Affairs for NorthernStar Natural Gas, a developer of liquefied natural gas import terminals that filed for bankruptcy protection under Chapter 7 in May 2010. From May 2005 to November 2006, Mr. Desmond served as Chairman of the California Energy Commission. From May 2006 to November 2006, Mr. Desmond also served as the Under Secretary for Energy Affairs in the California Resources Agency. Prior to his public service for the State of California, Mr. Desmond served as President and Chief Executive Officer of Infotility, Inc., an energy consulting and software development firm based in Boulder, Colorado. From 1997 to 2000, Mr. Desmond was President and Chief Executive Officer of Electronic Lighting, Inc., a manufacturer of controllable lighting systems, and from 1991 to 1997, a Vice President of Parke Industries, Inc., an energy efficient lighting systems company. Mr. Desmond serves on the board of directors of Lime Energy, Inc., a publicly-traded national energy services company. Mr. Desmond holds a B.S. in Business Administration from Northeastern University.

Arnold J. Goldman has served as the Chairman Emeritus of BrightSource and Chairman of BSII since October 2010. Mr. Goldman founded BrightSource in April 2004 and served as Chairman from April 2004 to October 2010. Mr. Goldman was the founder of Luz International, Ltd. and served as its Chief Executive Officer from 1980 to 1991. Mr. Goldman also co-founded Electric Fuel Ltd., an electric battery and fuel cell company listed today as Aerotech Corp. From 1970 to 1977, he was the Vice President of Engineering and co-founder of Lexitron Corporation, the first word processing company in the United States, which was acquired by Raytheon in 1977. Mr. Goldman holds a B.S. in Engineering from the University of California, Los Angeles and an M.S.E.E. from the University of Southern California. Mr. Goldman brings to our board of directors extensive management and leadership experience, a deep knowledge of the solar industry and of the financial and operational issues faced by us.

Daniel T. Judge has served as our General Counsel and Corporate Secretary since June 2008. Mr. Judge joined BrightSource after serving as Senior Counsel at Calpine Corporation from 2005 to 2007, where he was responsible for the legal aspects of project development and financing efforts in the western region of the United States. Prior to Calpine, Mr. Judge was Vice President and Senior Counsel at Bechtel Enterprises, the infrastructure project development and investment arm of the

Bechtel group of companies, from 1998 to 2005. There, he supported the development of airports, bridges and water systems, in addition to power projects. Mr. Judge began his legal career with the law firm of Orrick, Herrington & Sutcliffe LLP, where he specialized in corporate securities, project finance and commercial finance law. Mr. Judge has a J.D. from Boalt Hall at the University of California, Berkeley and an A.B. in American Studies from Stanford University.

Lynda Ward Pierce has served as our Senior Vice President of Human Resources and Administration since July 2010. Prior to joining BrightSource, Ms. Pierce served as Vice President of Human Resources at MobiTV, Inc. from August 2007 to July 2010. She also previously served as Head of Human Resources for SVB Financial Group, and as Vice President of Human Resources at Organic, Inc. from 1999 to 2007. From 1991 to 1999, she also held senior management roles at Navigant Consulting, Inc. and Mervyn’s Department Stores. Ms. Pierce holds a B.S. in Managerial Economics from the University of California, Davis, where she also attended the Graduate School of Management for a Masters in Management. She later completed the coursework for a Masters degree in Human Resources & Organizational Development from the College of Professional Studies at the University of San Francisco.

Stephen A. Wiley has served as our Senior Vice President of U.S. Project Development since August 2011. Prior to joining BrightSource, Mr. Wiley served as President of Gallop Power LLC, a developer, operator and owner of renewable projects focused on wind, biomass and solar projects, from August 2009 to August 2011. From August 2007 to August 2009, Mr. Wiley served as President of Greenhunter Energy, a diversified renewable energy investment company. From 2003 to 2007, Mr. Wiley served in management roles with increasing responsibility in the business development group at Gamesa Energy, a wind energy production company. From 2000 to 2003, he served as Vice President of TIP Strategies, a business and economic development consulting firm. Prior to that, Mr. Wiley served as Director, Business Development at Reliant Energy from 1998 to 2000, from 1991 to 1998, he held various positions at Dynegy (formerly Destec Energy) and from 1988 to 1991 he was a senior financial analyst for the Public Utility Commission of Texas. Mr. Wiley holds a B.S. in Petroleum Engineering from the University of Texas and an M.B.A. in Finance from the University of North Texas.

Nicholas E. Brathwaite has served as a member of our board of directors since April 2011. Mr. Brathwaite is a partner of Riverwood Capital LLC, a private equity firm he co-founded in January 2008. Mr. Brathwaite served as Chief Executive Officer of Aptina Imaging Corporation, a semiconductor company specializing in complementary metal-oxide-semiconductor image sensor technology, from 2008 to 2009, and is currently the Chairman of its board of directors. Mr. Brathwaite was the Chief Technology Officer of Flextronics International Ltd., an electronic manufacturing services company, from 2000 to 2007. In 1995, Flextronics International Ltd. acquired nChip, Inc., a multi-chip module company, where Mr. Brathwaite held the position of Vice President and General Manager of Operations from 1992 to 1996. Mr. Brathwaite currently serves a member of the board of directors of Power Integrations, Inc., a supplier of high-voltage analog integrated circuits for use in AC to DC power conversion and Tessera Technologies, Inc., a technology innovator that invests in, licenses and delivers innovative miniaturization technologies for next-generation electronic devices. He was also a member of the board of directors of Photon Dynamics, Inc., a public company and provider of products and services to flat panel display manufacturers, prior to its acquisition in October 2008. He received a B.S. in Applied Chemistry from McMaster University and a Masters in Polymer Engineering from the University of Waterloo. Mr. Brathwaite has also completed The Wharton School’s Executive Education Training on Corporate Governance at the University of Pennsylvania. Mr. Brathwaite’s technical background as well as his experience as an independent director of several public companies enable him to provide valuable insight and guidance to our management team and board of directors.

Denis Cochet has served as a member of our board of directors since March 2011. Mr. Cochet is currently Senior Vice President, Sales and Marketing for Alstom Thermal Power Sector. He began his career at Alstom in 1978 after serving two years in the French Navy. During Mr. Cochet’s tenure at

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Alstom, he has held a variety of positions including Sales and Marketing Vice President of Alstom Industrial Segment from 2003 to 2007, and Vice President of Sales for Alstom Power Sector since 2007. Mr. Cochet was educated in France and received a degree in statistics and economics from Ecole Nationale de la Statistique et de l’Administration Economique. Mr. Cochet brings to our board of directors more than three decades of experience in the international energy sector.

J. Stephan Dolezalek has served as a member of our board of directors since April 2011. He previously served as a member of our board of directors from November 2007 to May 2008. Mr. Dolezalek has served as Managing Director at VantagePoint Capital Partners, a venture capital investment firm since 1999 and Group Leader of the firm’s CleanTech Group since its inception in 2002. Mr. Dolezalek is an active participant in numerous cleantech advisory groups, including the American Council on Renewable Energy Leadership Council, the Center for American Progress Clean Tech Council, the California Energy Commission Public Interest Energy Research Program Advisory Board, and the University of Texas Energy Management and Innovation Center Advisory Board. At VantagePoint, Mr. Dolezalek previously served as head or co-head of the firm’s Software and Life Sciences Groups. Prior to joining VantagePoint, Mr. Dolezalek was a senior partner with Brobeck, Phleger & Harrison acting as Managing Partner of that firm’s Palo Alto office, Head of the Business and Technology Group and Chairman of the Life Sciences Group. Mr. Dolezalek received a B.S. from the School of Architecture at the University of Virginia and a J.D. from and the University of Virginia School of Law. He serves on the board of directors of the University of Virginia School of Architecture Foundation. With his background as a venture capitalist, Mr. Dolezalek brings to our broad of directors broad experience in advising and managing alternative energy companies, including expertise in capital raising, financial budgeting, strategy and operations.

James “Jim” Eats has served as a member of our board of directors since May 2007. Mr. Eats is currently President and Chief Executive Officer of Garden Energy, a renewable energy company he co-founded in November 2007. From 2006 to 2008, Mr. Eats served as Chief Executive Officer of Transformative Energy & Environment, Inc., a strategic advisory and hybrid equities firm with a focus on cleantech and sustainable businesses. From 2003 to 2006, Mr. Eats served as Division President—Americas for General Electric Wind Energy a division of General Electric Company, or GE. Prior to 2003, Mr. Eats served as GE Energy Region Executive and General Manager of South Asia, responsible for customer facing activities in 18 countries from Vietnam to New Zealand and he also led GE Power Systems-Korea, one of GE’s largest overseas markets. Mr. Eats received his Masters in Mechanical Engineering from Rensselaer Polytechnic Institute, and a B.S. in Engineering from Clarkson University. Mr. Eats brings to our board of directors significant experience in corporate leadership in multinational firms.

David C. Fries has served as a member of our board of directors since May 2008. He previously served as a member of our board of directors from October 2006 to November 2007. Mr. Fries has been employed by VantagePoint Capital Partners, a venture capital investment firm, since August 2001 where he currently serves as a Managing Director. Prior to joining VantagePoint, he was the Chief Executive Officer of Productivity Solutions, Inc., a Florida-based developer of automated checkout technologies for food and discount retailers, from 1995 to 1999. For seven years prior to that, he was a General Partner of Canaan Partners, a venture capital firm. Mr. Fries served 17 years in numerous executive roles in engineering, manufacturing, senior management and finance at GE, including directing GE Venture Capital’s California operation, which later became Canaan Partners. Mr. Fries served as a director of Aviza Technology, Inc., a supplier of advanced semiconductor equipment and process technologies for the global semiconductor industry, from 2003 until November 2007 and as a Director of Finisar Corporation, a provider of optical subsystems and components to system manufacturers for communication applications, from 2005 to 2010. Mr. Fries holds a B.S. in Chemistry from Florida Atlantic University and a Ph.D. in Physical Chemistry from Case Western Reserve University. Mr. Fries brings to our board of directors extensive management and finance

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experience in several industry and operational areas from his prior experience as an executive of several companies and a venture capital investor.

Richard C. Kelly was elected Chairman of our board of directors in December 2011. From December 2005 to September 2011, Mr. Kelly served as Chairman and Chief Executive Officer of Xcel Energy Inc., a holding company with subsidiaries engaged primarily in the utility business, including natural gas and electric services in eight states. From June 2005 to December 2005, Mr. Kelly was President and Chief Executive Officer of Xcel Energy Inc.; he previously served as Chief Financial Officer of the company. Mr. Kelly also served as President and Chief Operating Officer of NRG Energy, Inc., a former subsidiary of Xcel Energy Inc., from 2002 to 2003 and director of NRG Energy, Inc. from 2000 to 2003. In May 2003, NRG Energy, Inc. and certain of its affiliates filed voluntary petitions for reorganization under Chapter 11, emerging from bankruptcy in December 2003. Prior to the merger of New Century Energies and Northern States Power Company to form Xcel Energy Inc. in 2000, Mr. Kelly served as New Century Energies’ Chief Financial Officer. He is currently on the board of Canadian Pacific Railway and Chairman of the Board of Trustees at Regis University. Mr. Kelly was 2011 Chairman of the Edison Electric Institute, Chairman of the Board of Trustees of the Science Museum of Minnesota and a board member of the Capital City Partnership, the Electric Power Research Institute, and the Nuclear Energy Institute. He was also a member of the Minnesota Business Partnership, the National Petroleum Council, Colorado Concern and Colorado Forum and the National Advisory Council of the National Renewable Energy Laboratory. Mr. Kelly holds a B.S. in Accounting and an M.B.A. from Regis University. He attended the University of Colorado’s Executive Education Conference and The University of Michigan’s Public Utility Executive Program. Mr. Kelly brings extensive experience and knowledge of the utility industry and has demonstrated leadership in business and corporate governance.

Thomas M. O’Flynn has served as a member of our board of directors since June 2010. Since May 2010, Mr. O’Flynn has been a senior advisor to The Blackstone Group, assisting the Private Equity Group’s efforts in the power and utility sector. During this period, Mr. O’Flynn has been Chief Operating Officer and Chief Financial Officer of Transmission Developers, Inc., a Blackstone controlled company. From 2001 to 2009, Mr. O’Flynn was the Executive Vice President and Chief Financial Officer of Public Service Enterprise Group Incorporated where he had responsibility for operating and corporate financial and strategic functions for the diversified energy company. He also served as President of PSEG Energy Holdings from 2007 to 2009. From 1986 to 2001, Mr. O’Flynn was in the Global Power and Utility Group of Morgan Stanley during which he served as a Managing Director from 1996 to 2001 and as Head of the North American Power Group from 2000 to 2001. He was responsible for senior client relationships and led a number of large merger, financing, restructuring and advisory transactions. Mr. O’Flynn served on the board of directors for Nuclear Electric Insurance Limited from 2003 to 2009 and was Chairman of the Finance Executive Advisory Committee of the Edison Electric Institute from 2006 to 2008. He holds a B.A. in Economics from Northwestern University and an M.B.A. in Finance from the University of Chicago. Mr. O’Flynn brings to our board of directors 25 years of energy finance and utility experience.

Our executive officers are appointed by, and serve at the discretion of, our board of directors. There are no familial relationships among our directors and officers.

Code of Ethics

Prior to the closing of the offering, our board of directors will adopt a Code of Ethics that applies to all of our employees, officers and directors, including our Chief Executive Officer, Chief Financial Officer and other principal executive and senior financial officers. Our Code of Ethics will be posted on our website. We intend to disclose future amendments to certain provisions of our Code of Ethics, or waivers of these provision, on our website.

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Board of Directors

Our board of directors currently consists of nine members. All of our current directors were elected or appointed in accordance with the terms of our amended and restated certificate of incorporation and an amended and restated voting agreement among us and certain of our stockholders. The amended and restated voting agreement provides that VantagePoint Capital Partners, Morgan Stanley BrightSource LLC and Alstom Power Inc., so long as they hold a certain number of shares, are each entitled to designate one director nominee, pursuant to which J. Stephan Dolezalek, Thomas O’Flynn and Denis Cochet were elected as directors, respectively. The voting agreement also provides that our Chief Executive Officer, John Woolard, will serve as the representative of the common stockholders. The remaining directors are to be nominated by the holders of at least a majority of the preferred stock and elected by a majority of the preferred and common stock voting together on an as-converted to common stock basis, who currently are James Eats, Arnold Goldman, David Fries and Nicholas Brathwaite. The amended and restated voting agreement will terminate upon the completion of this offering, and there will be no further contractual obligation regarding the election of our directors. Our bylaws permit our board of directors to establish by resolution the actual number of directors within a range of seven to nine.

Mr. O’Flynn serves as our lead independent director. In this role, Mr. O’Flynn is available for consultation and communication with our stockholders and performs such other duties as our board of directors may designate.

Our board of directors will be divided into three classes effective upon the closing of the offering. The Class I directors, , and , will serve an initial term until the 2012 Annual Meeting of Stockholders, the Class II directors, , and , will serve an initial term until the 2013 Annual Meeting of Stockholders, and the Class III directors, , and , will serve an initial term until the 2014 Annual Meeting of Stockholders. Each class will be elected for three-year terms following its respective initial term.

Director Independence

Upon the completion of this offering, our common stock will be listed on The Nasdaq Global Select Market. Under the rules of The Nasdaq Stock Market, independent directors must comprise a majority of a listed company’s board of directors within a specified period of the completion of this offering. In addition, the rules of The Nasdaq Stock Market require that, subject to specified exceptions, each member of a listed company’s audit, compensation and nominating and governance committees be independent. Audit committee members must also satisfy the independence criteria set forth in Rule 10A-3 under the Securities Exchange Act of 1934, as amended, or the Exchange Act. Under the rules of The Nasdaq Stock Market, a director will only qualify as an “independent director” if, in the opinion of that company’s board of directors, that person does not have a relationship that would interfere with the exercise of independent judgment in carrying out the responsibilities of a director.

In order to be considered to be independent for purposes of Rule 10A-3, a member of an audit committee of a listed company may not, other than in his capacity as a member of the audit committee, the board of directors or any other board committee: (1) accept, directly or indirectly, any consulting, advisory or other compensatory fee from the listed company or any of its subsidiaries; or (2) be an affiliated person of the listed company or any of its subsidiaries.

In , our board of directors undertook a review of its composition, the composition of its committees and the independence of each director. Based upon information requested from and provided by each director concerning his background, employment and affiliations, including family relationships, our board of directors has determined that none of Messrs. Brathwaite, Dolezalek, O’Flynn, Eats and Fries, representing five of our eight directors, has a relationship that would interfere

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with the exercise of independent judgment in carrying out the responsibilities of a director and that each of these directors is “independent” as that term is defined under the rules of The Nasdaq Stock Market. Our board of directors also determined that Messrs. O’Flynn, Kelly and Eats, who comprise our audit committee, Messrs. Dolezalek, Eats and Brathwaite, who comprise our compensation committee and Messrs. O’Flynn, Kelly and Fries, who comprise our nominating and governance committee, satisfy the independence standards for those committees established by applicable SEC rules and the rules of The Nasdaq Stock Market. In making this determination, our board of directors considered the relationships that each non-employee director has with our company and all other facts and circumstances our board of directors deemed relevant in determining their independence, including the beneficial ownership of our capital stock by each non-employee director.

Committees of the Board of Directors

Our board of directors has established an audit committee, a compensation committee and a nominating and governance committee, each of which have the composition and responsibilities described below.

Audit Committee

Our audit committee is currently comprised of Messrs. O’Flynn, Kelly and Eats, each of whom is a non-employee member of our board of directors. Mr. O’Flynn is our audit committee chairman and is our audit committee financial expert, as currently defined under the SEC rules. Prior to the completion of this offering, our board of directors will adopt a charter for our audit committee. We expect that our audit committee to be responsible for, among other things:

reviewing and approving the selection of our independent auditors, and approving the audit and non-audit services to be performed by our independent auditors;

monitoring the integrity of our financial statements and our compliance with legal and regulatory requirements as they relate to financial statements or accounting matters;

reviewing the adequacy and effectiveness of our internal control policies and procedures;

discussing the scope and results of the audit with the independent auditors and reviewing with management and the independent auditors our interim and year-end operating results; and

preparing the audit committee report that the SEC requires in our annual proxy statement.

Compensation Committee

Our compensation committee is currently comprised of Messrs. Dolezalek, Brathwaite and Eats, each of whom is a non-employee member of our board of directors. Mr. Dolezalek is our compensation committee chairman. Prior to the completion of this offering, our board of directors will adopt a new charter for our compensation committee. We expect that our compensation committee will be responsible for, among other things:

overseeing our compensation policies, plans and benefit programs;

reviewing and approving for our executive officers: the annual base salary, the annual incentive bonus, including the specific goals and amount, equity compensation, employment agreements, severance arrangements and change in control arrangements, and any other benefits, compensations or arrangements;

preparing the compensation committee report that the SEC requires to be included in our annual proxy statement; and

administering our equity compensation plans.

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Nominating and Governance Committee

Our nominating and governance committee is comprised of Messrs. Fries, Kelly and O’Flynn, each of whom is a non-employee member of our board of directors. Mr. Kelly is the chairman of our nominating and governance committee. Prior to the completion of this offering, our board of directors will adopt a charter for our nominating and governance committee. We expect that our nominating and governance committee will be responsible for, among other things:

identifying, evaluating and recommending to the board of directors for nomination candidates for membership on the board of directors;

preparing and recommending to our board of directors corporate governance guidelines and policies; and

identifying, evaluating and recommending to the board of directors the chairmanship and membership of each committee of the board.

We intend to post the charters of our audit, compensation, and nominating and governance committees, and any amendments that may be adopted from time to time, on our website.

Compensation Committee Interlocks and Insider Participation

The members of the compensation committee of our board of directors are currently Messrs. Dolezalek, Brathwaite and Eats. None of Messrs. Dolezalek, Brathwaite and Eats has at any time been an officer or employee of BrightSource or any subsidiary of BrightSource.

Director Compensation

In July 2011, our board of directors adopted a director compensation policy which subsequently was made effective October 1, 2011, pursuant to which members of the board of directors who are not employees will receive annual directors’ fees consisting of the following:

Board of Directors Member—$50,000

Chairman of the Board—$100,000

Chair of Audit Committee—$22,500

Chair of Compensation Committee—$15,000

Chair of Nominating and Governance Committee—$7,500

Member of Audit Committee—$15,000

Member of Compensation Committee—$10,000

Member of Nominating and Governance Committee—$5,000

Effective upon completion of this offering, non-employee directors will also be entitled to receive an initial long-term equity incentive grant in the form of stock options with a target Black-Scholes value of $127,500 upon the commencement of their service as a director and an annual grant of restricted stock units with a target value of $85,000, as calculated by the closing stock price on the date of grant.

Effective upon completion of this offering, the new compensation policy will also include an equity ownership guideline whereby our directors will be expected to own and hold shares of our common stock with a value equal to at least three times the annual retainer fee, or $150,000. Each director will be expected to satisfy the target ownership threshold within five years from the completion of this offering and new directors will be expected to satisfy the target ownership threshold within five years

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from the date of his or her respective appointment as a director. Directors who are employees of BrightSource are eligible to participate in BrightSource’s 2011 Stock Option Plan. We also reimburse non-employee directors for travel, lodging and other expenses incurred in connection with their attendance at board or committee meetings.

Director Compensation Table

The following table sets forth the total compensation for our non-employee directors for the year ended December 31, 2011.


Name(1,2)	Fees Earned or Paid in Cash ($)		Option Awards ($)(3)		Total ($)
Nicholas E. Brathwaite		—		—		—
John E. Bryson(4)	$	35,806		—	$	35,806
Denis Cochet		—		—		—
Mark Coxon(5)		—		—		—
J. Stephan Dolezalek		—		—		—
Jim Eats	$	64,250		—	$	64,250
David C. Fries		—		—		—
Richard C. Kelly	$	884	$	495,976	$	496,860
Thomas M. O’Flynn	$	55,929		—	$	55,929

(1)	Mr. Goldman is a member of our board of directors and is an executive officer, but not a named executive officer, and does not receive any additional compensation for services provided as a director.

(2)	Mr. Woolard is a member of our board of directors and is an executive officer, but does not receive any additional compensation for services provided as a director.

(3)	Please see the outstanding equity awards table below for the details of the option awards.

(4)	Mr. Bryson resigned as a member of our board of directors effective June 27, 2011, in connection with his nomination to be the next U.S. Secretary of Commerce.

(5)	Mr. Coxon resigned as a member of our board of directors effective March 2, 2011.

The following table lists all outstanding equity awards held by our non-employee directors as of December 31, 2011.


Name	Grant Date		Number of Securities Underlying Unexercised Options Exercisable (#)		Number of Securities Underlying Unexercised Options Unexercisable		Option Exercise Price		Option Expiration Date		Option Awards ($)(1)
Nicholas E. Brathwaite		—		—		—		—		—		—
John E. Bryson(2)		9/20/2010		0		0	$	4.83		9/19/2020	$	371,500
Denis Cochet		—		—		—		—		—		—
Mark Coxon(3)		—		—		—		—		—		—
J. Stephan Dolezalek		—		—		—		—		—		—
Jim Eats		5/11/2007		36,666		3,334	$	0.47		5/10/2017	$	15,000
		3/4/2009		12,460		0	$	2.96		3/3/2019	$	28,470
		4/28/2010		4,500		4,500	$	4.26		4/27/2020	$	30,048
		9/20/2010		12,000		28,000	$	4.83		9/19/2020	$	148,604
David C. Fries		—		—		—		—		—		—
Richard C. Kelly(4)		12/19/2011		0		95,000	$	6.65		12/19/2021	$	495,976
Thomas M. O’Flynn		9/20/2010		10,095		30,285	$	4.83		9/19/2020	$	150,016

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(1)

Reflects the grant date fair value of each award computed in accordance with FASB ASC Topic 718. These amounts do not correspond to the actual value that will be recognized by the directors. The assumptions used in the valuation of these awards are consistent with the valuation methodologies specified in the notes to our consolidated financial statements.

(2)	Mr. Bryson resigned as a member of our board of directors effective June 27, 2011, in connection with his nomination to be the next U.S. Secretary of Commerce.

(3)	Mr. Coxon resigned as a member of our board of directors effective March 2, 2011.

(4)	Mr. Kelly was elected to our board of directors effective December 29, 2011.

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EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

The following discussion and analysis of compensation arrangements of our named executive officers for the year ended December 31, 2011 should be read together with the compensation tables and related disclosures set forth below.

This discussion contains information regarding our executive compensation programs that are based on our current plans and historical practices, as well as considerations, expectations and determinations regarding future compensation programs that we may adopt as we evolve from a pre-IPO company to a publicly traded company. While we have endeavored to include statements about how our compensation programs may evolve in a post-IPO environment based upon our current expectations, the actual compensation programs that we ultimately adopt may differ materially from currently planned programs summarized in this discussion.

Named Executive Officers

The individuals in the Summary Compensation Table set forth after this Compensation Discussion and Analysis are referred to as the “named executive officers,” or NEOs, and include the Chief Executive Officer, the Chief Financial Officer and the three other most highly compensated executive officers. Our NEOs also include a former executive officer who would have been one of the most highly compensated executive officers had he remained an executive officer through December 31, 2011. Our NEOs for 2011 were:

John Woolard – President, Chief Executive Officer and Director

Jack Jenkins-Stark – Chief Financial Officer

Joseph Desmond – Senior Vice President of Government Affairs and Communications

Israel Kroizer – Executive Vice President of R&D and Product Supply BSE/ President BSII

Stephen Wiley – Senior Vice President of U.S. Development

Carlos Aguilar – formerly the Senior Vice President of Project Execution and International Development

Role of the Compensation Committee in Setting Executive Compensation

The compensation committee has the overall responsibility for assessing performance and recommending to our board of directors the compensation and benefits of our NEOs. In addition, the compensation committee reviews and approves the short- and long-term incentive strategy and plans.

Members of the compensation committee are appointed by the board of directors. Mr. Eats served on the compensation committee for the entire calendar year 2011. During calendar year 2011, the following changes were made to the compensation committee: (1) Mr. Dolezalek replaced Mr. Fries on May 4, 2011 and is currently the Committee Chair; (2) Mr. Bryson resigned effective June 27, 2011 upon his nomination to be the U.S. Secretary of Commerce; and (3) Mr. Brathwaite was appointed on August 16, 2011 to replace Mr. Bryson.

None of the compensation committee members are executive officers of the Company. Messrs. Brathwaite, Eats, and Dolezalek are, and at all times of service during calendar year 2011 were, independent directors as defined under the NASDAQ Stock Market listing rules. Mr. Bryson was an independent director during his time of service during calendar year 2011.

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Role of Compensation Consultant

During 2011, the compensation committee retained Aon Hewitt as its outside consultant to assist the compensation committee as part of its decision-making process with regard to executive compensation related matters. Aon Hewitt provided no services directly for management with regard to executive compensation or other matters.

Role of Chief Executive Officer in Compensation Decisions

For executive officers other than our Chief Executive Officer, the compensation committee has sought input from our Chief Executive Officer and our Human Resources department regarding executive officers’ responsibilities, performance and compensation levels. The Chief Executive Officer, often in conjunction with analyses prepared by the Human Resources department and outside consultants, recommends base salary increases, bonus awards and equity award levels and advises the compensation committee regarding the compensation program’s ability to attract, motivate and retain executive talent. Specific analyses relied upon by the Chief Executive Officer in making such recommendations are referenced in the subsequent sections discussing the specific compensation actions taken during calendar year 2011.

The compensation committee considers the Chief Executive Officer’s recommendations, but may adjust pay up or down at its discretion, and approves the specific compensation for all the executive officers. Our compensation committee relies on the experience of our directors, who serve in both public and private companies, to determine and approve compensation. Our compensation committee meets in executive sessions, and our Chief Executive Officer does not attend discussions where recommendations are made or discussed regarding his compensation.

Compensation Philosophy

Our compensation philosophy supports our mission, values and goals, and recognizes that our employees are vital to our success. BrightSource’s objective is to provide fair, attractive, competitive, and flexible total compensation that allows us to attract, motivate, and retain exceptionally talented executives and employees. We seek executives and employees who have the skills and abilities needed to achieve desired business results, and who perform in alignment with our core values of integrity, ethics, safety, and industry leadership. We are a company that strives to perform and compete among the top of our industry peers, and we set our compensation levels accordingly.

The Company seeks the best available sources of external pay data to benchmark compensation in our target labor market, recognizing that competitive pay levels can differ by geography, role, or other market characteristics. After considering external reference data, the Company exercises judgment in setting what we believe is appropriately competitive compensation.

For senior roles, the Company generally intends to place a higher proportion of pay at risk, tied to measurable performance metrics aligned with key financial and operational benchmarks. Likewise, the mix of compensation and relative market positioning may vary by functional area and general market practices.

We seek to achieve our compensation objectives through a variety of compensation elements which are summarized in the table below.

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Key Elements of Compensation


Element	Objectives	Characteristics

Base Salary	Ÿ Attract, motivate and retain qualified employees and executives at a level of skill and performance commensurate with the expectations we set for the Company as a whole. Ÿ Set compensation based on an individual’s skills, experience and performance. Ÿ Recognize and reward alignment of performance with our core values.	Ÿ Not at risk. Ÿ Commensurate with position, level of responsibility and leadership role. Ÿ The Company places significant weight on an employee’s/executive’s role within the Company, his or her leadership responsibilities, performance during the last year and his or her ability to impact the overall Company performance. Ÿ The Company exercises judgment when setting base salary based on relative importance of the individual, the role and other external market factors.

Short- to Mid-Term Incentives	Ÿ Attract, motivate and retain qualified employees/executives. Ÿ Motivate and reward achievement of Company, department and individual short- and mid-term goals and objectives. Ÿ Reward growth and career progression between base pay adjustments and to cover periods of exceptional performance.	Ÿ At risk. Ÿ This element includes performance-based cash or other awards. Ÿ Targets are based upon job function, level of responsibility and ability to impact the Company’s performance. Ÿ Actual awards are discretionary and consider Company and individual results achieved relative to goals, as well as individual performance factors such as demonstrated excellence, teamwork and leadership. Ÿ The Company also balances current results with future expectations to reward outstanding performance by an individual.

Long-Term Incentives	Ÿ Attract, motivate and retain qualified employees/executives. Ÿ Align the interests of employees/executives with those of the Company’s stockholders. Ÿ Provide long-term rewards for employees/executives based upon stock price appreciation.	Ÿ At risk. Ÿ Equity should represent a meaningful portion of executive total compensation to ensure that stockholder value remains a primary objective. Ÿ Actual awards vary depending on the Company’s stock performance.

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Compensation Data and Comparator Group

The Company uses several data sources for the competitive compensation benchmarking of its executives in the United States and Israel.

Throughout the year, the compensation committee met with and made requests of Aon Hewitt with respect to comparator data. Beginning in March 2011, Aon Hewitt, in conjunction with Company management and under the compensation committee’s review and input, conducted an analysis of the Company’s compensation benchmarking peers for executive talent. Aon Hewitt conducted several market screens to identify a preliminary peer group. The pool of companies considered and subsequent screens incorporated the following:

Existing BrightSource peer group companies;

Companies identified by the Company’s investment bankers as comparable with a similar business model or industry focus;

Solar-related, energy, independent power producers, heavy electrical equipment, utilities, multi-utilities, environmental and facilities services, construction and engineering and semiconductor (solar-related) companies; and

Companies with market capitalizations generally between $750 million to $3 billion and revenues between $200 million and $2 billion.

The compensation committee selected the following companies as a peer group to use as reference for benchmarking executive and Board compensation and benefits:

A123 Systems, Inc.

American Superconductor Corporation

Argan, Inc.

Atlantic Power Corporation

Michael Baker Corporation

Broadwind Energy, Inc.

Calpine Corporation

Emcore Corporation

Energy Conversion Devices, Inc.

Finisar Corporation

First Solar, Inc.

GT Solar International, Inc.

MYR Group, Inc.

Ormat Technologies, Inc.

Pike Electric Corp.

Power-One, Inc.

Powersecure International, Inc.

Premier Power Renewable Energy

Satcon Technology Corp.

Solazyme, Inc.

Sunpower Corporation

Tesla Motors Inc.

Tetra Tech Inc.

TRC Companies, Inc.

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In addition, the Company referenced compensation benchmarking data for pre-IPO, technology and power industry firms from the following published survey sources:

Radford High Technology Executive Compensation Survey data for participating U.S.-based companies with $200 million to $500 million in revenue and Radford country-specific compensation data for executive positions based in Israel.

IEHRA Energy Industry Compensation survey data for non-regulated companies.

Zviran’s Salary Survey, covering compensation at Israeli companies in the high-tech and information technology industries.

We use the above as a “guiding” compensation philosophy given that our industry segment is highly unique. There are few firms that are precisely comparable to us in all aspects of revenue, technology and scope. For this reason we reference compensation data from a variety of sources, including pre-IPO and public high technology, alternative energy and power companies ranging in revenue size and scope. The compensation committee does not use the above data rigidly and uses its discretion and independent judgment when positioning individual executive pay. We will continue to assess and adjust our executive compensation philosophy on a going-forward basis as we transition from being a private to a public company and continue to grow in size of revenues and assets.

Pay Mix

When reviewing the compensation of executive officers vis-a-vis the market data, the compensation committee did generally take into consideration the mix of fixed versus variable compensation. As a previously non-public entity, the Company has not yet adopted a specific policy regarding fixed versus incentive pay due to the variability in the valuation of long-term incentives provided in the form of Company stock options. Going forward, the Company will continue to monitor both BrightSource’s and the competitive market’s fixed and incentive pay levels.

Base Salaries

The compensation committee periodically reviews the salaries of our executives as a group and individually. The factors considered when establishing a base salary for each executive officer include, but are not limited to, the individual’s performance, relevant experience, role, responsibilities and contribution level and external market practices (market data). Base salaries are generally targeted between the median and 75^th percentile of the external market.

On March 18, 2011, the compensation committee approved an increase to the base salary for Mr. Woolard, increasing it from $395,000 to $445,000 (12.7%) retroactive to January 1, 2011. This base salary increase was made to reflect the compensation committee’s interpretation of external market data indicating that his base salary was below our desired competitive market positioning, and the continued growth and scale of the Company. More specifically, this competitive market analysis indicated that Mr. Woolard’s base salary of $395,000 was below the 50th percentile ($420,000) for Bay Area public technology/alternative energy companies and also below the 50th percentile ($406,800) for independent power industry companies.

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Annual Cash Incentive Program

The 2011 Short-Term Incentive Plan is a discretionary incentive plan that measures both Company and individual performance. The plan was designed to fund a discretionary award pool up to 100% of the target bonus opportunities of our executives for meeting certain individual objectives and the Company’s key corporate objectives, which were as follows:

achievement of key Enhanced Oil Recovery (EOR) milestones;

closing of Ivanpah financing, transition of ownership responsibilities, and ensuring on-budget and on-schedule provision of the BrightSource scope of supply;

obtaining sufficient operating capital to fund planned growth;

securing a post-Ivanpah site in the U.S.;

enhance positioning for future growth through R&D efforts to improve cost/performance;

strategic initiatives to expand our development footprint internationally; and

maintaining current revenue streams through PPAs in the U.S. and developing new ones for the future.

Satisfaction of the above goals, together with an evaluation of each NEO’s performance against his or her individual goals, forms the basis upon which the compensation committee intends to exercise its discretion in awarding individual bonuses. The plan is not intended by the compensation committee to be formulaic in nature. Thus, the compensation committee did not pre-establish fixed weighting for individual versus corporate goals or among the corporate goals. Additionally, the compensation committee did not specifically identify threshold levels or maximum levels of performance to trigger payouts.

The compensation committee has not yet assessed the Company’s achievement against the 2011 goals, nor the individual NEOs’ performance for 2011. Consequently, NEO bonuses for 2011 have not yet been determined nor awarded.

The following table summarizes the potential target bonuses for each NEO for the 2011 performance year:


Executive	2011 Base Salary (Bonus Basis)		2011 Target Bonus (%)			2011 Target Bonus ($)		2011 Actual Bonus ($)
John Woolard	$	445,000		75	%	$	333,750		To be determined
Jack Jenkins-Stark	$	295,000		50	%	$	147,500		To be determined
Israel Kroizer(1)	$	245,000		45	%	$	110,250		To be determined
Joseph Desmond(2)	$	275,000		35	%	$	38,500		To be determined
Stephen Wiley(3)	$	230,000		35	%	$	33,600		To be determined
Carlos Aguilar(4)	$	250,000		45	%	$	103,125		To be determined

(1)	The basis for Mr. Kroizer’s 2011 bonus calculation will be $245,000 to control for the impact of currency exchange fluctuations.

(2)	The target bonus amount for Mr. Desmond is prorated to reflect his partial year of service during 2011.

(3)	The target bonus amount for Mr. Wiley is prorated to reflect his partial year of service during 2011.

(4)	The target bonus amount for Dr. Aguilar is prorated to reflect his partial year of service during 2011.

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In addition to the bonuses described above, on April 27, 2011 the compensation committee awarded a one-time gross cash award of $100,000 to Mr. Jenkins-Stark in recognition of his leadership in successfully completing the project financing for our Ivanpah project.

Annual Cash Incentive Program – Post-IPO

The Company’s current short-term incentive plan is a fully discretionary cash bonus plan which will be superseded by the BrightSource Energy, Inc. Short-Term Incentive plan upon the closing of the offering. The BrightSource Energy, Inc. Short-Term Incentive Plan, or the Short-Term Incentive Plan, is in a form consistent with the current plan’s structure with additional provisions to reflect the Company’s status as publicly-traded. On July 2, 2011, the board of directors approved the Short-Term Incentive Plan to become effective upon the closing of the offering. The new Short-Term Incentive Plan will first provide for bonuses for the 2012 plan year and its purpose is to motivate and reward eligible employees for their contributions toward the achievement of certain performance goals, with the intention that the incentives paid thereunder to certain executive officers of the Company are deductible under Section 162(m) of the Code, and the regulations and interpretations promulgated thereunder. The Short-Term Incentive Plan will be administered by the compensation committee, which shall have the discretionary authority to interpret the provisions of the Short-Term Incentive Plan, including all decisions on eligibility to participate, the establishment of performance goals, the amount of awards payable under the plan, and the payment of awards.

Equity Compensation

Stock options are our primary vehicle for offering long-term incentives to our executives. We believe that equity grants help to align the interests of our executives and stockholders, provide our executives with incentives linked to long-term performance and create an ownership culture. Stock options granted in 2011 have a 10-year term and become vested and exercisable at a rate of 1/5th of the shares on the first anniversary of the grant and 1/60th of the original number of shares at the end of each month thereafter. Select stock option grants prior to 2011 had a different vesting schedule. We believe the vesting schedule of the equity grants contributes to executive retention as the vesting provides an incentive for our executives to remain employed during the period. Prior to this IPO, our executives have been eligible to participate in our 2006 Stock Plan, which will be superseded by the 2011 Omnibus Equity Incentive Plan upon the effective date of the offering. Stock options are granted at 100% of fair market value, or FMV, on the date of grant as determined by the compensation committee with the input of an independent valuation by a valuation firm engaged by the Company to perform periodic Internal Revenue Code section 409A valuations of the Company’s stock, applying valuation techniques and methods that rely on recommendations by the American Institute of Certified Public Accountants, or AICPA, in its Audit and Accounting Practice Aid and conform to generally accepted valuation practices.

Specific equity grants made to the NEOs in 2011 were:

Mr. Desmond: 160,000 stock options granted on September 9, 2011 with respect to his hire by the Company.

Mr. Wiley: 100,000 stock options granted on September 9, 2011 with respect to his hire by the Company.

Following the IPO closing, executives will be eligible to receive long-term incentive awards under the 2011 Omnibus Equity Incentive Plan.

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Stock Option Grant Practices

The compensation committee approves all equity grants that are made to any executive officer of the Company, including the NEOs. Initial grants to executives have typically been made upon their hire, and in some cases subsequent grants have been made to reward performance, to provide additional retention incentives or to better align the executive’s compensation with target market compensation levels. Going forward following the IPO, our general intent is to provide annual refresh grants to executives based upon performance, retention need, and prevalent market compensation practices.

In the past, we have not granted stock options on a focal grant date. Post-IPO, we intend to grant long-term incentive equity on a common annual date, effective after any material non-public information (such as our earnings) has been released to the public.

In addition, we are in the process of determining whether to use other forms of long-term incentive awards (e.g., cash-based and other stock vehicles) as part of our long-term incentive mix going forward.

Stock Ownership Guidelines

The Company does not currently have formal stock ownership guidelines for our executive officers because we believe our current incentive compensation arrangements provide the appropriate alignment between executive officers and our stockholders. We will continue to review best practices and evaluate our position with respect to stock ownership guidelines.

Employee Benefits

Our NEOs are eligible to participate in the benefit programs that are generally available to all of the Company’s employees in their respective country (United States or Israel) of employment. Other than any contractual individual arrangements described in the sections titled “—Employment Agreements and Offer Letters” and “—Severance and Change in Control Agreements,” including providing Messrs. Woolard and Jenkins-Stark with annuity contracts and a parking allowance, and Mr. Kroizer with vehicle expense reimbursement, the Company does not provide any supplemental executive benefits to NEOs.

Severance Agreements with Executive Officers

The compensation committee has approved severance and change in control agreements for each of our executive officers in order to provide reasonable protection when a change in control could affect their security, authority or compensation. This also promotes the interests of stockholders by mitigating executives’ concerns about such personal matters and thereby assuring that management provides guidance to the board of directors and stockholders that is divorced from such concerns. Moreover, this also will help to ensure that the management team stays intact before, during and after a change in control, thereby protecting the interests of stockholders as well as the acquirer.

These severance and change and control agreements supersede and replace the terms of such executive officer’s employment agreement or offer letter with respect to severance and change in control payments, where applicable. For information on the severance and change in control agreements, see “—Severance and Change in Control Agreements” below. Also see “—Potential Payments Upon Termination or Change in Control” below.

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Clawbacks of Incentive Compensation

As part of our transition from a privately-held to publicly-traded company, the intent of the Company and the compensation committee is to implement during this fiscal year a formal set of standards addressing the treatment of previously paid or awarded executive incentives in the event of certain circumstances in which it is later determined by the board of directors or the compensation committee, in their sole discretion, that fraud, misconduct, negligence or other material noncompliance with any financial reporting requirements under securities laws significantly contributed to a misstatement of financial results that led to the awarding of unearned incentive compensation. It is our intent that such clawback standards will fully comply with the requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act requiring repayment of any excess incentive-based compensation paid during the three-year period preceding the date that the Company is required to prepare the accounting restatement based upon erroneous data.

Tax Deductibility of Executive Compensation

Because of limitations of Code Section 162(m), we generally receive a tax deduction for compensation paid to our Chief Executive Officer and to certain other executive officers only if the compensation is less than $1 million per person during any fiscal year or is performance-based as defined under Code Section 162(m).

In addition to salary and bonus compensation, upon exercise of stock options that are not treated as incentive stock options, the excess of the current market price over the option price, or option spread, is treated as compensation and accordingly, in any year, such exercise may cause an officer’s compensation to exceed $1 million. Option spread compensation from options that meet certain requirements will not be subject to the $1 million cap on deductibility, and in the past we have granted options that we believe meet those requirements.

The compensation committee intends to maintain an approach that links pay to performance and, while the compensation committee has not formally adopted a policy regarding tax deductibility of compensation paid to our named executive officers, the compensation committee intends to consider tax deductibility under the Code Section 162(m) as a factor in compensation decisions.

Risk Review of Compensation Plans

Generally, the Company and the compensation committee do not believe that any of our compensation plans encourage executives or employees to engage in unnecessary or excessive risks that would threaten the value of the Company. As part of our overall evaluation of compensation programs that we will perform as part of our evolution toward becoming a publicly traded company, the compensation committee will more formally review the Company’s compensation plans and the associated potential risks. More specifically, we will review:

the compensation plans applicable to our executive officers to reaffirm and ensure that they do not encourage them to take unnecessary and excessive risks that threaten the value of the Company and that any potential risks are appropriately mitigated;

employee compensation plans in light of the risks posed to the Company by these plans and how such risks are limited; and

our executive and employee compensation plans to reaffirm and ensure that these plans do not encourage the manipulation of the reported earnings of the Company to enhance the compensation of any of the Company’s employees.

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Compensation for Named Executive Officers

Summary Compensation Table

The following table sets forth information regarding the compensation that we paid to each of our named executive officers during the year ended December 31, 2011.


Name and Principal Position	Salary ($)			Bonus ($)			Option Awards ($)(1)		Change in Pension Value and Nonqualified Deferred Compensation Earnings		All Other Compensation ($)			Total ($)
John Woolard	$	445,000			TBD	(10)		0		—	$	41,145	(2)	$	486,145
President and Chief Executive Officer

Jack Jenkins-Stark Chief Financial Officer	$	295,000		$	100,000 +TBD	(11)		0		—	$	33,093	(3)	$	428,093

Israel Kroizer	$	248,935			TBD	(10)		0		—	$	70,669	(5)	$	319,604
Executive Vice President, Engineering, R&D, and Product Supply of BrightSource and President of BSII(4)

Joseph Desmond	$	109,375			TBD	(10)	$	1,103,360		—	$	10,200	(6)	$	1,222,935
Senior Vice President, Government Affairs and Communications

Stephen Wiley	$	95,455			TBD	(10)	$	689,600		—	$	200		$	785,255
Senior Vice President, U.S. Development

Carlos Aguilar Senior Vice President, Project Execution & International Development	$	264,331	(7)	$	37,500 +TBD	(8,10)		0		—	$	156,100	(9)	$	457,930

(1)

Reflects the grant date fair market value of each award computed in accordance with FASB ASC Topic 718. These amounts do not correspond to the actual value that will be recognized by the named executive officers. The assumptions used in the valuation of these awards are consistent with the valuation methodologies specified in the notes to our consolidated financial statements.

(2)	Includes $35,625 contributed by BrightSource to a deferred annuity contract for the benefit of Mr. Woolard, plus employer-paid contributions related to this annuity contribution and parking.

(3)	Includes $28,125 contributed by BrightSource to a deferred annuity contract for the benefit of Mr. Jenkins-Stark, plus employer-paid contributions related to this annuity contribution and parking.

(4)	The amounts paid to Mr. Kroizer were paid in Israeli shekels, or ILS, and the amounts above were converted from ILS to U.S. dollars, based on the exchange rate on December 31, 2011 of ILS 1 = $3.8195.

(5)

Includes a $39,406 employer contribution to Mr. Kroizer’s manager’s insurance policy (pension and severance fund components), a $3,702 employer contribution to Mr. Kroizer’s education fund, a $12,990 employer contribution to the Israeli National Insurance Fund, $13,640 in automobile related expenses and convalescence pay.

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(6)	Reflects a $10,000 new hire signing bonus for Mr. Desmond.

(7)	Reflects $231,061 in base salary paid during 2011, $14,331 in accrued vacation and personal holiday time paid out upon termination of employment and $18,939 in salary continuation as provided in Dr. Aguilar’s separation agreement.

(8)	Reflects a $37,500 retention bonus payable on January 1, 2011 in accordance with Dr. Aguilar’s employment offer letter dated November 20, 2009.

(9)	Reflects $156,100 for reimbursement of relocation expenses.

(10)	The compensation committee has not yet determined achievement of the corporate objectives and satisfaction of individual performance goals for 2011 and therefore has not yet established the 2011 bonus amount.

(11)

The compensation committee has not yet determined achievement of the corporate objectives and satisfaction of individual performance goals for 2011 and therefore has not yet established the 2011 bonus amount. In addition to the 2011 bonus amount, the compensation committee awarded a one-time gross cash award of $100,000 to Mr. Jenkins-Stark in recognition of his leadership in successfully completing the project financing of our Ivanpah project.

Grants of Plan-Based Awards

The following table sets forth information regarding the grants of plan-based awards to each of our named executive officers during the year ended December 31, 2011.


Name	Grant Date (1)		All Other Option Awards: Number of Securities Underlying Options (#)		Exercise or Base Price of Option Awards ($/Sh)		Grant Date Fair Value of Option Awards($)(2)
John Woolard		N/A		—		—		—
Jack Jenkins-Stark		N/A		—		—		—
Israel Kroizer		N/A		—		—		—
Joseph Desmond		9/9/2011		160,000	$	9.81	$	1,103,360
Stephen Wiley		9/9/2011		100,000	$	9.81	$	689,600
Carlos Aguilar		N/A		—		—		—

(1)	The vesting schedule applicable to each award is set forth below in the section entitled “Outstanding Equity Awards at Fiscal Year-End.”

(2)

Reflects the grant date fair value of each award computed in accordance with FASB ASC Topic 718. These amounts do not correspond to the actual value that will be recognized by the named executive officers. The assumptions used in the valuation of these awards are consistent with the valuation methodologies specified in the notes to our consolidated financial statements.

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Outstanding Equity Awards at Fiscal Year-End

The following table shows all outstanding equity awards held by each of our named executive officers at December 31, 2011.


	Option Awards
Name	Grant Date		Vesting Commencement Date			Number of Securities Underlying Unexercised Options Exercisable (#)		Number of Securities Underlying Unexercised Options Unexercisable (#)		Option Exercise Price ($)		Option Expiration Date
John Woolard		11/15/2006		9/5/2006	(1)		1,246,125		—	$	0.35		11/14/2016
		7/9/2007		5/16/2007	(2)		280,000		20,000	$	0.47		7/8/2017
		9/20/2010		9/1/2010	(3)		350,000		1,050,000	$	4.83		9/19/2020
Jack Jenkins-Stark		5/11/2007		5/1/2007	(4)		338,333		41,667	$	0.47		5/10/2017
		9/20/2010		9/1/2010	(4)		63,426		190,279	$	4.83		9/19/2020
Israel Kroizer		11/15/2006		10/1/2006	(5)		600,000		—	$	0.01		11/14/2016
		5/13/2008		2/12/2008	(6)		153,333		46,667	$	3.70		5/12/2018
		9/20/2010		9/1/2010	(6)		37,500		112,500	$	4.83		9/19/2020
Joseph Desmond		9/9/2011		8/8/2011	(6)		—		160,000	$	9.81		9/9/2021
Stephen Wiley		9/9/2011		8/8/2011	(6)		—		100,000	$	9.81		9/9/2021
Carlos Aguilar		4/28/2010		1/10/2010	(6)		105,416		169,584	$	4.26		4/27/2020
		9/20/2010		9/1/2010	(6)		25,000		75,000	$	4.83		9/19/2020

(1)

25,000 shares subject to the option vest each month. 36,000 shares subject to the option vested upon the closing of BrightSource’s Series A preferred stock financing. Vesting is accelerated in certain situations. See “—Potential Payments Upon Termination or Change in Control,” “—Employment Agreements and Offer Letters” and “—Severance and Change in Control Agreements” below.

(2)

1/60 of the total number of shares subject to the option vest on the vesting commencement date and at the end of each 30 days thereafter. Vesting is accelerated in certain situations. See “—Potential Payments Upon Termination or Change in Control,” “—Employment Agreements and Offer Letters” and “—Severance and Change in Control Agreements” below.

(3)

1/5 of the total number of shares subject to the option vest on the first anniversary of the vesting commencement date and 1/60 of the remaining shares subject to the option vest monthly thereafter until all shares are vested. Vesting is accelerated in certain situations. See “—Potential Payments Upon Termination or Change in Control,” “—Employment Agreements and Offer Letters” and “—Severance and Change in Control Agreements” below.

(4)

(5)

1/20 of the total number of shares subject to the option vest on the vesting commencement date, of the remaining 570,000 shares subject to the option, 1/5 of the total number of shares subject to the option vest on the first anniversary of the vesting commencement date and 1/60 of the total number of shares subject to the option vest monthly thereafter until all shares are vested. Vesting is accelerated in certain situations. See “—Severance and Change in Control Agreements” below.

(6)

1/5 of the total number of shares subject to the option vest on the first anniversary of the vesting commencement date and 1/60 of the remaining shares subject to the option vest monthly thereafter until all shares are vested. Vesting is accelerated in certain situations. See “—Severance and Change in Control Agreements” below.

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Option Exercises and Stock Vested

During 2011, Mr. Woolard and Mr. Jenkins-Stark exercised stock options as detailed below:


Name	Option Awards				Stock Awards
Name	Number of Shares Acquired on Exercise		Value Realized on Exercise		Number of Shares Acquired on Vesting		Value Realized on Vesting
John Woolard		190,000	$	938,600		—		—
Jack Jenkins-Stark		120,000	$	578,400		—		—

Pension Benefits

None of our named executive officers participate in or have account balances in qualified or non-qualified defined benefit plans sponsored by us.

Nonqualified Deferred Compensation

The following table provides information on the executive non-qualified deferred compensation activity for each of our named executive officers for the year ended December 31, 2011.


Name	Executive Contributions in Last Fiscal Year ($)			Registrant Contributions in Last Fiscal Year ($)			Aggregate Earnings (Losses) in Last Fiscal Year ($)			Aggregate Withdrawals/ Distributions ($)		Aggregate Balance at Last Fiscal Year End ($)
John Woolard		—		$	35,625	(1)	($	32,023	)(2)		—	$	208,515	(3)
Jack Jenkins-Stark		—		$	28,125	(1)	($	25,983	)(2)		—	$	145,353	(3)
Israel Kroizer	$	13,681	(4)	$	43,109	(7)	($	19,893	)(6)		—	$	318,871	(7)
Joseph Desmond		—			—			—			—		—
Stephen Wiley		—			—			—			—		—
Carlos Aguilar		—			—			—			—		—

(1)	This amount represents employer contributions to such executive’s deferred annuity contract and is included in the “All Other Compensation” column of the Summary Compensation table.

(2)

This amount represents the dollar value by which the balance of such executive’s deferred annuity contract as of December 31, 2011 exceeds the sum of (i) the balance of the deferred annuity contract as of December 31, 2010, and (ii) the employer contributions made to the deferred annuity contract during fiscal 2011.

(3)

(4)	This amount represents contributions by Mr. Kroizer to his education fund and manager’s insurance policy.

(5)	This amount represents a $39,406 employer contribution to Mr. Kroizer’s manager’s insurance policy and a $3,702 employer contribution to Mr. Kroizer’s education fund. These amounts are included in the “All Other Compensation” column of the Summary Compensation table.

(6)

This amount represents the dollar value by which the aggregate balance of Mr. Kroizer’s manager’s insurance policy and education fund as of December 31, 2011 is less than the sum of (i) the balance of the manager’s insurance policy and education fund as of December 31, 2010, and (ii) the employer and employee contributions to the manager’s insurance policy and education fund during fiscal 2011.

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(7)	This amount represents the aggregate balance of Mr. Kroizer’s manager’s insurance policy and education fund as of December 31, 2011.

Potential Payments Upon Termination or Change in Control

The following table discloses potential payments and benefits under our compensation and benefit plans and other employment arrangements to which certain of our executive officers would be entitled upon a termination of their employment or change of control, assuming the termination of employment or change in control occurred on December 31, 2011.


	By Company Without Cause(1)			Disability or Death(1)			Following Change in Control
Name	By Company Without Cause(1)			Disability or Death(1)			By Company Without Cause(1)			By Executive for Good Reason or following a Constructive Termination(1)			Disability or Death(1)
John Woolard
Cash Payments	$	667,500	(2)	$	208,515	(3)	$	1,557,500	(4)	$	1,557,500	(4)	$	208,515	(3)
Accelerated Equity Awards		—			—		$	2,034,600	(5)	$	2,034,600	(5)		—
COBRA and Outplacement	$	66,629			—		$	66,629		$	66,629			—
Jack Jenkins-Stark
Cash Payments	$	295,000	(6)	$	145,353	(7)	$	663,750	(8)	$	663,750	(8)	$	145,353	(7)
Accelerated Equity Awards		—			—		$	603,810	(9)	$	603,810	(9)		—
COBRA and Outplacement	$	41,919			—		$	59,129		$	59,129			—
Israel Kroizer
Cash Payments	$	263,195	(10)	$	123,212	(11)	$	555,693	(12)	$	555,693	(12)	$	123,212	(11)
Accelerated Equity Awards		—			—		$	342,418	(13)	$	342,418	(13)		—
Outplacement	$	7,500			—		$	7,500		$	7,500			—
Joseph Desmond
Cash Payments	$	137,500	(14)		—		$	371,250	(15)	$	371,250	(15)		—
Accelerated Equity Awards		—			—		$	0	(16)	$	0	(16)		—
COBRA and Outplacement	$	24,710			—		$	41,920		$	41,920			—
Stephen Wiley
Cash Payments	$	120,000	(17)		—		$	324,000	(18)	$	324,000	(18)		—
Accelerated Equity Awards		—			—		$	0	(19)	$	0	(19)		—
COBRA and Outplacement	$	24,710			—		$	41,920		$	41,920			—

(1)

Such amounts to be reduced by applicable taxes and withholdings. Further, the amounts shown in the table above do not include any payments or benefits to the extent they are provided on a non-discriminatory basis to salaried employees generally upon a termination of employment. These include (i) accrued salary and, if applicable, accrued and unused vacation time, and (ii) distributions of plan balances under our 401(k) plan.

(2)	This amount represents 18 months’ base salary of Mr. Woolard.

(3)	This amount represents the amount accrued under Mr. Woolard’s deferred annuity contract that was payable to Mr. Woolard’s designated beneficiaries in the event of his death on December 31, 2011.

(4)	This amount represents 24 months’ base salary of Mr. Woolard plus 200% of Mr. Woolard’s target bonus for 2011.

(5)	This amount represents the value of the full acceleration of vesting of all then-unvested shares subject to the options granted to Mr. Woolard based upon a fair market value of a share of our common stock of $6.65 as of December 31, 2011.

(6)	This amount represents 12 months’ base salary of Mr. Jenkins-Stark.

(7)	This amount represents the amount accrued under Mr. Jenkins-Stark deferred annuity contract that was payable to Mr. Jenkins-Stark’s designated beneficiaries in the event of his death on December 31, 2011.

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(8)	This amount represents 18 months’ base salary of Mr. Jenkins-Stark plus 150% of Mr. Jenkins-Stark’s target bonus for 2011.

(9)	This amount represents the value of the full acceleration of vesting of all then-unvested shares subject to the options granted to Mr. Jenkins-Stark based upon a fair market value of a share of our common stock of $6.65 as of December 31, 2011.

(10)	This amount represents 12 months’ base salary of Mr. Kroizer plus $14,260 accrued under an educational fund held by BrightSource in favor of Mr. Kroizer, converted from ILS to U.S. dollars, based on the exchange rate on December 31, 2011 of ILS 1 = $3.8195.

(11)	This amount represents $108,952 payable to Mr. Kroizer pursuant to the Israeli Severance Pay Law and $14,260 accrued under an educational fund held by BrightSource in favor of Mr. Kroizer.

(12)

This amount represents 18 months’ base salary of Mr. Kroizer, plus 150% of Mr. Kroizer’s target bonus for 2011, plus $14,260 accrued under an educational fund held by BrightSource in favor of Mr. Kroizer, converted from ILS to U.S. dollars, based on the exchange rate on December 31, 2011 of ILS 1 = $3.8195.

(13)	This amount represents the value of the full acceleration of vesting of all then-unvested shares subject to the options granted to Mr. Kroizer based upon a fair market value of a share of our common stock of $6.65 as of December 31, 2011.

(14)	This amount represents 6 months’ base salary of Mr. Desmond.

BrightSource Energy Inc S-1/A