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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2010

Commission File Number: 001-33480

CLEAN ENERGY FUELS CORP.
(Exact name of registrant as specified in its charter)

3020 Old Ranch Parkway, Suite 400, Seal Beach CA 90740
(Address of principal executive offices, including zip code)

(562) 493-2804
(Registrant's telephone number, including area code)

        Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ý

        Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232,405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o    No o

        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 definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

        Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act). Yes o    No ý

        As of May 3, 2010, there were 60,865,892 shares of the registrant's common stock, par value $0.0001 per share, issued and outstanding.

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

INDEX

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PART I.—FINANCIAL INFORMATION

Item 1.—Financial Statements (Unaudited)

Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Balance Sheets

December 31, 2009 and March 31, 2010 (Unaudited)

See accompanying notes to condensed consolidated financial statements.

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Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Statements of Operations

For the Three Months Ended

March 31, 2009 and 2010

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

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Clean Energy Fuels Corp.

Condensed Consolidated Statements of Cash Flows

For the Three Months Ended March 31, 2009 and 2010

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1—General

        Nature of Business:    Clean Energy Fuels Corp. (the "Company") is engaged in the business of selling natural gas fueling solutions to its customers primarily in the United States and Canada. The Company has a broad customer base in a variety of markets including public transit, refuse, airports and regional trucking. The Company operates, maintains or supplies approximately 200 natural gas fueling locations in Arizona, California, Colorado, District of Columbia, Florida, Georgia, Idaho, Maryland, Massachusetts, Nevada, New Jersey, New Mexico, New York, Ohio, Oklahoma, Texas, Virginia, Washington and Wyoming within the United States, and in British Columbia and Ontario within Canada. The Company also generates revenue through operation and maintenance agreements with certain customers, through building and selling or leasing natural gas fueling stations to its customers, and through financing its customers' vehicle purchases. In April 2008, the Company opened its first compressed natural gas ("CNG") station in Lima, Peru through the Company's joint venture, Clean Energy del Peru. In August 2008, the Company acquired 70% of the outstanding membership interests of Dallas Clean Energy, LLC ("DCE"). DCE owns a facility that collects, processes and sells renewable biomethane collected from a landfill in Dallas, Texas. On October 1, 2009, the Company acquired 100% of BAF Technologies, Inc., a company that provides natural gas conversions, alternative fuel systems, application engineering, service and warranty support and research and development for natural gas vehicles.

        Basis of Presentation:    The accompanying interim unaudited condensed consolidated financial statements include the accounts of the Company and its subsidiaries, and, in the opinion of management, reflect all adjustments, which include only normal recurring adjustments, necessary to state fairly the Company's financial position, results of operations and cash flows for the three months ended March 31, 2009 and 2010. All intercompany accounts and transactions have been eliminated in consolidation. The three month periods ended March 31, 2009 and 2010 are not necessarily indicative of the results to be expected for the year ending December 31, 2010 or for any other interim period or for any future year.

        Certain information and disclosures normally included in the notes to consolidated financial statements have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (the "SEC"), but the resultant disclosures contained herein are in accordance with accounting principles generally accepted in the United States of America as they apply to interim reporting. The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements as of and for the year ended December 31, 2009 that are included in the Company's Annual Report on Form 10-K filed with the SEC on March 10, 2010.

Note 2—Acquisitions

Operating and Maintenance Contracts

        In May 2009, the Company acquired four compressed natural gas operations and maintenance services contracts for $5.6 million in cash. The Company recorded $0.5 million to tangible assets and $5.1 million of intangible assets related to customer relationships, which are being amortized over their expected lives of eight years. The results of operations of the acquired contracts are included in the Company's consolidated financial statements from their acquisition dates forward, which are May 2009 for two of the contracts and June 2009 for the remaining two contracts. In addition, as part of the acquisition, the Company became the custodian of certain customer-owned inventories that it is

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 2—Acquisitions (Continued)

required to replenish when the contracts expire. The customer-owned inventory was valued on the Company's books at $986,000 with a corresponding balance of $986,000 recorded as a liability on the acquisition dates of the contracts.

Vehicle Conversion

        On October 1, 2009, the Company purchased all the outstanding shares of BAF under a stock purchase agreement. The Company paid an aggregate of $8.5 million to acquire BAF. Pursuant to the terms of the agreement, the purchase price was reduced by the amount of BAF's outstanding debt, which was repaid in full at closing. Due to the fact that approximately $3.8 million of BAF's outstanding debt, including interest, was held by Clean Energy, the Company paid a net amount of approximately $4.7 million in cash to acquire BAF at the closing. BAF shareholders will be able to earn additional consideration if BAF achieves certain gross profit targets in fiscal 2010 and 2011. The additional consideration will be determined as a percentage of gross profit based on a sliding scale that increases at certain gross profit levels, subject to achieving a minimum gross profit target and capped by a maximum additional payment amount. For 2010, the shareholders of BAF will receive between one and twenty-six percent of the gross profit of BAF as additional consideration if BAF achieves $8 million or more in gross profit, up to a maximum of $11 million in additional consideration (which maximum amount would be payable if BAF achieved approximately $42.3 million in gross profit in 2010).

        For 2011, the shareholders of BAF will receive between one and twenty-one percent of the gross profit of BAF as additional consideration if BAF achieves $8.5 million or more in gross profit, up to a maximum of $11 million in additional consideration (which maximum amount would be payable if BAF achieved approximately $52.4 million in gross profit in 2011). The Company accounted for this acquisition in accordance with authoritative guidance for business combinations which requires the Company to recognize the assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree at the acquisition date, measured at their fair values as of that date of acquisition. The following table summarizes the allocation of the aggregate purchase price to the fair value of the assets acquired and liabilities assumed:

        Management allocated approximately $10.7 million of the purchase price to the identifiable intangible assets related to customer relationships, engine certifications and trademarks that were acquired with the acquisition. The fair value of the identifiable intangible assets will be amortized on a straightline basis over their estimated useful lives of 1.5 to 8 years. In addition, management allocated

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 2—Acquisitions (Continued)

$774,142 to goodwill as part of the acquisition and recorded a contingent liability of $3.1 million related to the possible consideration owed to BAF shareholders if BAF achieves certain gross profit targets in 2010 and 2011. Under the accounting guidance the Company must follow for this acquisition, the Company is required to adjust the value of the contingent consideration for this acquisition in the statement of operations as the value of the obligation changes each reporting period. During the three month period ended March 31, 2010, the Company increased its contingent liability by $0.3 million, which is included in selling, general and administrative expenses in the accompanying condensed consolidated statement of operations. The value of the obligation will increase or decrease in relation to any increase or decrease in the anticipated gross profit of BAF.

        The results of BAF's operations have been included in the Company's consolidated financial statements since October 1, 2009.

Note 3—Cash and Cash Equivalents

        The Company considers all highly liquid investments with maturities of three months or less on the date of acquisition to be cash equivalents.

Note 4—Natural Gas Derivative Financial Instruments

        The Company, in an effort to manage its natural gas commodity price risk exposures related to certain contracts, utilizes derivative financial instruments. The Company, from time to time, enters into natural gas futures contracts that are over-the-counter swap transactions that convert its index-based gas supply arrangements to fixed-price arrangements. The Company accounts for its derivative instruments in accordance with authoritative guidance for derivative instruments and hedging activities, which requires the recognition of all derivatives as either assets or liabilities in the condensed consolidated balance sheet and the measurement of those instruments at fair value. Historically, through June 30, 2008, the Company's derivative instruments have not qualified for hedge accounting under the authoritative guidance. On and after July 1, 2008, the Company entered into futures contracts that did qualify for hedge accounting. The Company's futures contracts at March 31, 2009 and 2010 are being accounted for as cash flow hedges under the authoritative guidance and are being used to mitigate the Company's exposure to changes in the price of natural gas and not for speculative purposes. At March 31, 2009 and 2010, all of the Company's futures contracts qualified for hedge accounting.

        The counter-party to the Company's derivative transactions is a high credit quality counterparty; however, the Company is subject to counterparty credit risk to the extent the counterparty to the derivatives is unable to meet its settlement commitments. The Company manages this credit risk by minimizing the number and size of its derivative contracts. The Company actively monitors the creditworthiness of its counterparties and records valuation adjustments against the derivative assets to reflect counterparty risk, if necessary. The counter-party is also exposed to credit risk of the Company, which requires the Company to provide cash deposits as collateral.

        The Company marks to market its open futures positions at the end of each period and records the net unrealized gain or loss during the period in derivative (gains) losses in the condensed consolidated statements of operations or in accumulated other comprehensive income in the condensed

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 4—Natural Gas Derivative Financial Instruments (Continued)

consolidated balance sheets in accordance with the guidance. The Company recorded an unrealized gain of approximately $33,000 and an unrealized loss of approximately $3.9 million in accumulated other comprehensive income for the three month periods ended March 31, 2009 and 2010, respectively, related to its futures contracts. Of the approximately $3.7 million liability for the Company's futures contracts at March 31, 2010, approximately $1.9 million is included in accrued liabilities for the short-term amount, and approximately $1.8 million is included in other long-term liabilities for the long-term amount in the Company's condensed consolidated balance sheet at March 31, 2010. The liability for the Company's futures contracts of approximately $621,000 at March 31, 2009 is included in accrued liabilities on the Company's condensed consolidated balance sheet at March 31, 2009. The Company's ineffectiveness related to its futures contracts during the three month periods ended March 31, 2009 and 2010, respectively, was insignificant. For the three month periods ended March 31, 2009 and 2010, the Company recognized a loss of approximately $500,000 and a gain of approximately $213,000, respectively, in cost of sales in the accompanying condensed consolidated statements of operations related to its futures contracts that were settled during the respective three-month periods.

        The Company is required to make certain deposits on its futures contracts, should any exist. At March 31, 2009, the Company had $1.1 million of margin deposits related to its futures contracts covering approximately 1.6 million gasoline gallon equivalents of natural gas fuel, all of which were current and recorded in prepaid expenses and other current assets at March 31, 2009. At March 31, 2010, the Company had $5.4 million of margin deposits related to its futures contracts covering approximately 26.1 million gasoline gallon equivalents of fuel, of which $2.5 million were current at March 31, 2010. These deposits are recorded in prepaid expenses and other current assets and notes receivable and other long-term assets in the accompanying condensed consolidated balance sheet as of March 31, 2010.

        The following table presents the notional amounts and weighted average fixed prices per gasoline gallon equivalent of the Company's natural gas futures contracts as of March 31, 2010:

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 5—Other Receivables

        Other receivables at December 31, 2009 and March 31, 2010 consisted of the following:

Note 6—Land, Property and Equipment

        Land, property and equipment at December 31, 2009 and March 31, 2010 are summarized as follows:

Note 7—Investments in Other Entities

        Through March 31, 2010, the Company invested approximately $10.0 million in The Vehicle Production Group LLC ("VPG"), a company that is developing a natural gas vehicle made in the United States for taxi and paratransit use. On April 22, 2010, VPG made a capital call requiring the Company to invest approximately $0.4 million in additional funds, which the Company funded. The Company has now met its investment commitment to VPG and will not be required to invest additional funds under its original investment commitment. The Company accounts for its investment in VPG under the cost method of accounting as the Company does not have the ability to exercise significant influence over VPG's operations.

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 8—Accrued Liabilities

        Accrued liabilities at December 31, 2009 and March 31, 2010 consisted of the following:

Note 9—Long-term Debt

        In conjunction with the Company's acquisition of its 70% interest in DCE on August 15, 2008, the Company entered into a Credit Agreement with PCB. The Company borrowed $18.0 million (the "Facility A Loan") to finance the acquisition of its membership interests in DCE. The Company also obtained a $12.0 million line of credit from PCB to finance capital improvements of the DCE processing facility and to pay certain costs and expenses related to the acquisition and the PCB loans (the "Facility B Loan"). As of March 31, 2010, the Company had an outstanding balance of $9.9 million under the Facility B Loan. On October 7, 2009, the Facility A Loan was repaid in full and converted into a line of credit (the "A Line of Credit") pursuant to an amendment to the Credit Agreement. The Company did not have any amounts outstanding under the A Line of Credit at March 31, 2010. Interest accrues daily on the amounts outstanding under the Credit Agreement at the greater of the prime rate of interest for the United States plus 0.50% per annum or 5.50% per annum. The principal amount of the Facility B Loan became due and payable in annual payments commencing on August 1, 2009, and continuing each anniversary date thereafter, with each such payment being in an amount equal to the lesser of twenty percent of the aggregate principal amount of the Facility B Loan then outstanding or $2,800,000. On August 15, 2013, the remaining amount of unpaid principal and interest under the Facility B Loan is due and payable. Any amounts outstanding under the A Line of Credit are due August 15, 2010, which the Company can extend for one year if it is not in default of the A Line of Credit. The Company paid a facility fee of $300,000 in connection with the Credit Agreement. As of March 31, 2010, the unamortized balance of the facility fee was $202,500. Amortization of the facility fee is recorded as additional interest expense in the consolidated statements of operations.

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 9—Long-term Debt (Continued)

        The Credit Agreement requires the Company to comply with certain covenants. The Company may not incur indebtedness or liens except as permitted by the Credit Agreement, or declare or pay dividends. The Company must maintain, on a quarterly basis, minimum liquidity of not less than $6.0 million, accounts receivable balances, as defined, of not less than $8.0 million, consolidated net worth, as defined, of not less than $150.0 million, and a debt to equity ratio, as defined, of not more than 0.3 to 1. Beginning in the quarter ended June 30, 2009, the Company must also maintain a specific minimum debt service ratio at each quarter end. Effective in the fourth quarter of 2008, the Company established a lock-box arrangement with PCB subject to the Credit Agreement. Funds from the Company's customers are remitted to the lock-box and then deposited to a PCB bank account. The remitted funds are not used to pay-down the balance of the Credit Agreement. However, if the Company defaults on the Credit Agreement, all of the obligations under the Credit Agreement will become immediately due and payable and all funds received in the Company's lock-box held by PCB will be applied to the balance due on the A Line of Credit and Facility B Loan. One of the events of default is the occurrence of a "material adverse change," which is a subjective acceleration clause. Based on the authoritative guidance for balance sheet classification of borrowings outstanding under revolving credit agreements that include both a subjective acceleration clause and a lock-box arrangement, the Company has classified its debt pursuant to the Credit Agreement as short-term or long-term as appropriate and believes an event of default is more than remote but not more likely than not.

        One of the Company's bank covenants is a requirement to maintain accounts receivable balances from certain subsidiaries above $8.0 million at each quarter end during the term. Because the Company's revenues are dependent on the price of natural gas and the volume of natural gas the Company delivers, to the extent natural gas prices fall or the Company's volumes decline, the Company could violate this covenant in the future. Beginning with the quarter ended June 30, 2009, the Company is required to maintain a debt service ratio, as defined, of not less than 1.5 to 1. To the extent the Company's operating results do not materialize as anticipated, the Company could violate this covenant in the future. In the event the Company would violate either of these covenants, it would seek a waiver from the bank. The Company is in compliance with the covenants as of March 31, 2010. The Credit Agreement is secured by the Company's interest in, and note receivable from, DCE (described below), certain of the Company's accounts receivable and inventory balances and 45 of the Company's LNG tanker trailers. The net book value of the collateral securing the PCB loans was approximately $50.6 million at March 31, 2010. The Company maintains $2.5 million in a payment reserve account at PCB. PCB may, in the event of a default, withdraw funds from the account to apply to the principal and interest payments due on the A Line of Credit or the Facility B Loan. Such amount is included as restricted cash in the Company's condensed consolidated balance sheet at March 31, 2010.

        As part of the transaction, the Company also entered into a Loan Agreement with DCE (the "DCE Loan") to provide secured financing of up to $14.0 million to DCE for future capital expenditures or other uses as agreed to by the Company in its sole discretion. As of March 31, 2010, the Company is owed approximately $8.5 million under the DCE Loan. Interest on the unpaid balance accrues at a rate of 12% per annum and became payable quarterly beginning on September 30, 2008. The principal amount of the loan is due and payable in annual payments commencing on August 1, 2009, and continuing each anniversary date thereafter, with each such payment being in an amount equal to the lesser of the aggregate principal amount of the DCE Loan then outstanding or $2,800,000.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 9—Long-term Debt (Continued)

On August 1, 2013, the entire amount of unpaid principal and interest under the DCE Loan is due and payable. The principal and accrued interest balances as well as any interest income related to the DCE Loan are eliminated in the consolidated financial statements of the Company. Any event of default by DCE on the DCE Loan results in a cross-default of the Company's Credit Agreement with PCB. Events of default include failure to make payments when due, DCE's failure to perform under the provisions of its landfill lease with the City of Dallas, DCE's violation of a covenant under its operating agreement and other standard events of default.

        Principal payments for the following periods under the Facility B Loan at March 31, 2010 are as follows:

Note 10—Earnings Per Share

        Basic earnings per share is based upon the weighted average number of shares outstanding during each period. Diluted earnings per share reflects the impact of assumed exercise of dilutive stock options and warrants. The information required to compute basic and diluted earnings per share is as follows:

        Certain securities were excluded from the diluted earnings per share calculations at March 31, 2009 and 2010, respectively, as the inclusion of the securities would be anti-dilutive to the calculation. The amounts outstanding as of March 31, 2009 and 2010 for these instruments are as follows:

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 11—Comprehensive Income (Loss)

        The following table presents the Company's comprehensive loss for the three months ended March 31, 2009 and 2010:

Note 12—Stock-Based Compensation

        The following table summarizes the compensation expense and related income tax benefit related to the stock-based compensation expense recognized during the periods:

Stock Options

        The following table summarizes the Company's stock option activity during the three months ended March 31, 2010:

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 12—Stock-Based Compensation (Continued)

        The fair value of each option is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants in 2010:

        Based on these assumptions, the weighted average grant date fair value of options granted during the three months ended March 31, 2010 was $11.91.

Note 13—Use of Estimates

        The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and revenues and expenses during the reporting period. Actual results could differ from those estimates. Current economic conditions may require the use of additional estimates and these estimates may be subject to a greater degree of uncertainty as a result of the uncertain economy.

Note 14—Environmental Matters, Litigation, Claims, Commitments and Contingencies

        The Company is subject to federal, state, local, and foreign environmental laws and regulations. The Company does not anticipate any expenditures to comply with such laws and regulations that would have a material impact on the Company's consolidated financial position, results of operations, or liquidity. The Company believes that its operations comply, in all material respects, with applicable federal, state, local and foreign environmental laws and regulations.

        The Company may become party to various legal actions that arise in the ordinary course of its business. During the course of its operations, the Company is also subject to audit by tax authorities for varying periods in various federal, state, local, and foreign tax jurisdictions. Disputes may arise during the course of such audits as to facts and matters of law. It is impossible at this time to determine the ultimate liabilities that the Company may incur resulting from any lawsuits, claims and proceedings, audits, commitments, contingencies and related matters or the timing of these liabilities, if any. If these matters were to be ultimately resolved unfavorably, an outcome not currently anticipated, it is possible that such outcome could have a material adverse effect upon the Company's consolidated financial position or results of operations. However, the Company believes that the ultimate resolution of such actions will not have a material adverse affect on the Company's consolidated financial position, results of operations, or liquidity.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 15—Income Taxes

        The Company is required to recognize the impact of a tax position in its financial statements if the position is more likely than not of being sustained by the taxing authority upon examination, based on the technical merits of the position. The Company accrues interest based on the difference between a tax position recognized in the financial statements and the amount claimed on its returns at statutory interest rates. The net interest incurred was immaterial for the three months ended March 31, 2009 and 2010. Further, the Company accrues penalties if the tax position does not meet the minimum statutory threshold to avoid penalties. No penalties have been accrued by the Company. The Company's unrecognized tax benefits as of March 31, 2010 are unchanged from December 31, 2009.

        The Company is subject to taxation in the United States and various states and foreign jurisdictions. The Company's tax years for 2005 through 2009 are subject to examination by various tax authorities. The Company is no longer subject to U.S. examination for years before 2005, and state examinations for years before 2005. The Company is currently under audit by the Internal Revenue Service for tax years 2005 through 2008.

        The Company's tax benefit for the period ended March 31, 2010 includes a refund of approximately $1.3 million of alternative minimum taxes previously paid attributable to the Company's election of the extended net operating loss five-year carryback provision under the Worker, Homeownership, and Business Assistance Act of 2009.

Note 16—Fair Value Measurements

        On January 1, 2008, the Company adopted the authoritative guidance for fair value measurements which defines fair value, establishes a framework for measuring fair value and enhances disclosures about fair value measurements related to financial instruments. In December 2007, the Financial Accounting Standard Board ("FASB") provided a one-year deferral of this guidance for non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value on a recurring basis, at least annually. Accordingly, the Company adopted this guidance for non-financial assets and non-financial liabilities on January 1, 2009.

        During the three months ended March 31, 2010, the Company's financial instruments consisted of natural gas futures contracts, debt instruments, the contingent consideration related to its BAF acquisition, and its Series I warrants. The Company remeasures its contingent consideration based on the discounted future cash flows of BAF during the contingency period, which expires December 31, 2011. The Company records any change in its contingency obligation in selling, general and administrative expenses in its condensed consolidated statements of operations. The Company uses quoted forward price curves, discounted to reflect the time value of money, to value its natural gas futures contracts. The Company uses a Monte Carlo simulation model to value the Series I warrants, which requires the Company to make certain estimates including risk-free interest rates and the volatility of its stock price, among others. The Company's futures contracts and contingent consideration obligation are recorded in accrued liabilities for the short-term liability amount, and long-term liabilities for the long-term liability amount, and the Series I warrants are recorded in other long-term liabilities in the accompanying condensed consolidated balance sheet at March 31, 2010. The fair market value of the Company's debt instruments approximated their carrying values at March 31, 2010.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 16—Fair Value Measurements (Continued)

        The following table reflects the fair value as defined by the authoritative guidance of the Company's natural gas futures contracts and Series I warrants at March 31, 2009:

        The Company recorded a charge of $176,767 for the three month period ended March 31, 2009 in the statement of operations associated with the Series I warrants.

        The following table provides a reconciliation of the beginning and ending balances for the Series I warrants at fair value using significant unobservable inputs (Level 3) for the quarter ended March 31, 2009:

        The following table reflects the fair value as defined by the authoritative guidance of the Company's natural gas futures contracts, Series I warrants and contingent consideration at March 31, 2010:

        The Company recorded a charge of $300,000 and $18,604,798 for the three month period ended March 31, 2010 in the statement of operations associated with the contingent consideration and the Series I warrants, respectively.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 16—Fair Value Measurements (Continued)

        The following table provides a reconciliation of the beginning and ending balances for the contingent consideration and the Series I warrants at fair value using significant unobservable inputs (Level 3) for the quarter ended March 31, 2010:

Note 17—Recently Adopted Accounting Changes and Recently Issued Accounting Standards

        In June 2008, the FASB reached a consensus on determining whether an instrument (or embedded feature) is indexed to an entity's own stock. The FASB concluded, among other things, that contingent and other adjustment features in equity-linked financial instruments are consistent with equity indexation if they are based on variables that would be inputs to a "plain vanilla" option or forward pricing model and they do not increase the contract's exposure to those variables. The Company's Series I warrants issued on October 28, 2008 are linked to the Company's own equity shares; however, the investor has protective pricing features commonly referred to as "down-round" protection, whereby the conversion price potentially resets if the common stock price of the Company declines after issuance or shares are issued by the Company at prices below the exercise price of the warrants. As a result of this guidance, effective January 1, 2009, the Company accounts for the Series I warrants as a derivative. The Company recorded a cumulative-effect adjustment of approximately $2.6 million to opening retained earnings and reclassed approximately $9.8 million from additional paid-in capital to long-term liabilities on the date of adopting this guidance, January 1, 2009. During 2009 and during the three-month period ended March 31, 2010, the Company recorded charges of $17.4 million and $18.6 million, respectively, related to valuing the Series I warrants.

        In October 2009, the FASB issued new authoritative guidance on multi-deliverable revenue arrangements. This guidance establishes requirements that must be met for an entity to recognize revenue from the sale of a delivered item that is part of a multiple-element arrangement when other items have not yet been delivered. One of those current requirements is that there be objective and reliable evidence of the standalone selling price of the undelivered items, which must be supported by either vendor-specific objective evidence ("VSOE") or third party evidence ("TPE"). This guidance amends previous guidance by eliminating the requirement that all undelivered elements have VSOE or TPE before an entity can recognize the portion of an overall arrangement fee that is attributable to items that already have been delivered. In the absence of VSOE or TPE of the standalone selling price for one or more delivered or undelivered elements in a multiple-element arrangement, entities will be required to estimate the selling prices of those elements. The overall arrangement fee will be allocated to each element (both delivered and undelivered items) based on their relative selling prices, regardless of whether those selling prices are evidenced by VSOE or TPE or are based on the entity's estimated

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 17—Recently Adopted Accounting Changes and Recently Issued Accounting Standards (Continued)

selling price. Application of the "residual method" of allocating an overall arrangement fee between delivered and undelivered elements will no longer be permitted under this new guidance. Additionally, the new guidance will require entities to disclose more information about their multiple-element revenue arrangements. This guidance is effective June 15, 2010 and the Company is currently evaluating the impact of this guidance on is consolidated financial statements.

        In January 2010, the FASB issued new accounting guidance which intended to improve disclosures about fair value measurements. The guidance requires entities to disclose significant transfers in and out of fair value hierarchy levels, the reasons for the transfers and to present information about purchases, sales, issuances and settlements separately in the reconciliation of fair value measurements using significant unobservable inputs (Level 3). Additionally, the guidance clarifies that a reporting entity should provide fair value measurements for each class of assets and liabilities and disclose the inputs and valuation techniques used for fair value measurements using significant other observable inputs (Level 2) and significant unobservable inputs (Level 3). The Company has applied the new disclosure requirements as of January 1, 2010, and the adoption of this guidance did not have a material impact on the Company's consolidated financial statements.

Note 18—Volumetric Excise Tax Credit (VETC)

        The Company records its VETC credits as revenue in its condensed consolidated statements of operations as the credits are fully refundable and do not need to offset income tax liabilities to be received. VETC revenues for the three months periods ended March 31, 2009 and 2010 were approximately $4.1 million and $0.0 million, respectively. The legislation providing for VETC expired on December 31, 2009. Versions of a bill to extend the federal fuel excise tax credit have been passed by the United States House of Representatives and the Senate; however, the bills must successfully undergo a process whereby the two bills are combined into one bill and the resulting bill is signed into law by the President of the United States before becoming effective. We do not know when, if ever, these bills will pass through this process and be signed by the President.

        Legislation for new incentives for natural gas fuel or vehicles has been introduced in Congress, including HR 1835, the New Alternative Transportation to Give Americans Solutions Act ("NAT GAS Act"). However, the legislative process is inherently uncertain and therefore the Company does not know if or when any of the legislation providing for reinstatement, extension or new incentives for natural gas fuel or vehicles will be passed.

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Item 2.    Management's Discussion and Analysis of Financial Condition and Results of Operations.

        The following Management's Discussion and Analysis of Financial Condition and Results of Operations (this "MD&A") should be read together with the unaudited condensed consolidated financial statements and the related notes included elsewhere in this report. For additional context with which to understand our financial condition and results of operations, refer to the MD&A for the fiscal year ended December 31, 2009 contained in our 2009 Annual Report on Form 10-K with the SEC on March 10, 2010, as well as the consolidated financial statements and notes contained therein.

Cautionary Statement Regarding Forward Looking Statements

        This MD&A and other sections of this report contain forward looking statements. We make forward-looking statements, as defined by the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995, and in some cases, you can identify these statements by forward-looking words such as "if," "shall," "may," "might," "will likely result," "should," "expect," "plan," "anticipate," "believe," "estimate," "project," "intend," "goal," "objective," "predict," "potential" or "continue," or the negative of these terms and other comparable terminology. These forward-looking statements, which are based on various underlying assumptions and expectations and are subject to risks, uncertainties and other unknown factors, may include projections of our future financial performance based on our growth strategies and anticipated trends in our business. These statements are only predictions based on our current expectations and projections about future events that we believe to be reasonable. There are important factors that could cause our actual results, level of activity, performance or achievements to differ materially from the historical or future results, level of activity, performance or achievements expressed or implied by such forward-looking statements. These factors include, but are not limited to, those discussed under the caption "Risk Factors" in this report and in our 2009 Annual Report on Form 10-K. In preparing this MD&A, we presume that readers have access to and have read the MD&A in our 2009 Annual Report on Form 10-K pursuant to Instruction 2 to paragraph (b) of Item 303 of Regulation S-K. We undertake no duty to update any of these forward- looking statements after the date of filing of this report to conform such forward-looking statements to actual results or revised expectations, except as otherwise required by law.

Overview

        We provide natural gas solutions for vehicle fleets primarily in the United States and Canada. Our primary business activity is selling compressed natural gas ("CNG") and liquefied natural gas ("LNG") vehicle fuel to our customers. We also build, operate and maintain fueling stations, and help our customers acquire and finance natural gas vehicles and obtain local, state and federal clean air incentives. Our customers include fleet operators in a variety of markets, such as public transit, refuse hauling, airports, taxis and regional trucking. In April 2008, we opened our first compressed natural gas station in Lima, Peru, through our joint venture, Clean Energy del Peru. In August 2008, we acquired 70% of the outstanding membership interest of Dallas Clean Energy, LLC ("DCE"). DCE owns a facility that collects, processes and sells renewable biomethane collected from a landfill in Dallas, Texas. On October 1, 2009, we acquired 100% of BAF Technologies, Inc. ("BAF"), a company that provides natural gas conversions, alternative fuel systems, application engineering, service and warranty support and research and development for natural gas vehicles.

        The following overview discusses matters on which our management primarily focuses in evaluating our financial condition and operating performance as well as recent and anticipated business trends.

        Sources of revenue.    We generate the vast majority of our revenue from selling CNG and LNG and providing operations and maintenance services to our customers. The balance of our revenue is provided by designing and constructing natural gas fueling stations, financing our customers' natural gas vehicle purchases, sales of pipeline quality biomethane produced by our DCE joint venture and, beginning in the fourth quarter of 2009, sales of natural gas vehicles through our wholly owned subsidiary, BAF.

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        Key operating data.    In evaluating our operating performance, our management focuses primarily on: (1) the amount of CNG and LNG gasoline gallon equivalents delivered (which we define as (i) the volume of gasoline gallon equivalents we sell to our customers, plus (ii) the volume of gasoline gallon equivalents dispensed to our customers at stations where we provide operating and maintenance ("O&M") services but do not directly sell the CNG or LNG, plus (iii) our proportionate share of the gasoline gallon equivalents sold as CNG by our joint venture in Peru, plus (iv) our proportionate share of the gasoline gallon equivalents of biomethane produced and sold as pipeline quality natural gas by DCE); (2) our gross margin (which we define as revenue minus cost of sales), and (3) net income (loss). The following table, which you should read in conjunction with our condensed consolidated financial statements and notes contained elsewhere in this report, presents our key operating data for the years ended December 31, 2007, 2008 and 2009 and for the three months ended March 31, 2009 and 2010:

        Key trends in 2007, 2008, and 2009 and the first three months of 2010.    According to the U.S. Energy Information Administration, demand for natural gas fuels in the United States increased by approximately 29% during the period January 1, 2007 through December 31, 2009. We believe this growth in demand was attributable primarily to the rising prices of gasoline and diesel relative to CNG and LNG during these periods and increasingly stringent environmental regulations affecting vehicle fleets.

        The number of fueling stations we served grew from 147 at December 31, 2004 to 200 at March 31, 2010 (a 36.1% increase). Included in this number are all of the CNG and LNG fueling stations we own, maintain or with which we have a fueling supply contract. The amount of CNG and LNG gasoline gallon equivalents we delivered from 2005 to 2009 increased by 77.8%. The increase in gasoline gallon equivalents delivered was the primary contributor to increased revenues during these periods. Our cost of sales also increased during these periods, which was attributable primarily to increased costs related to delivering more CNG and LNG to our customers.

        During the last half of 2009 and the first quarter of 2010, we also experienced reduced margins in certain markets, particularly in the municipal transit and refuse sector. The reduction in margins is primarily a result of increased competition and sales agreements with larger entities that have greater pricing leverage. Also, in many cases, our agreements with our customers, including governmental agencies, are subject to a competitive bidding process and we may be required to reduce our prices to maintain our contracts as they come up for bid. We also have significant contracts with government entities that are experiencing large budget deficits and these customers have and may continue to demand price reductions for our services. In addition, in May and June of 2009, we acquired four compressed natural gas operations and maintenance services contracts with municipal transit agencies that have significant volume but smaller margins than we typically maintain on our fuel sales. As a result, the overall average margin on our fuel sales across our business decreased during these periods. We believe that our margins on fuel sales will improve in the future to the extent we are successful in growing our retail CNG and LNG fueling operations, which is where we earn our highest margin,

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relative to our lower-margin operations, such as municipal transit. If we are unsuccessful in growing our retail CNG and LNG fueling operations, we may experience reduced margins. We may also lose contracts with governmental customers if we are unwilling or unable to reduce our prices or lose in the competitive bidding process, which would reduce our volumes. For example, MTS of San Diego, which represented approximately 6 million gasoline gallon equivalents of our CNG volume in 2009, recently conducted a competitive bidding procurement and the staff of the MTS has recommended awarding the contract to a competitor. We are evaluating our options with respect to this contract. We will need to grow our business with non-government entities to replace volumes lost in competitive bid procurements where we are not successful in retaining the contracts.

        Anticipated future trends.    We anticipate that, over the long term, the prices for gasoline and diesel will continue to be higher than the price of natural gas as a vehicle fuel, and more stringent emissions requirements will continue to make natural gas vehicles an attractive alternative to traditional gasoline and diesel powered vehicles. Our belief that natural gas will continue, over the long term, to be a cheaper vehicle fuel than gasoline or diesel is based in part on the growth in U.S. natural gas production. A 2008 Navigant Consulting, Inc. study indicates that as a result of new unconventional gas shale discoveries from 22 basins in the U.S., maximum estimates of total recoverable domestic reserves from producers have increased to equal 118 years of U.S. production at 2007 production levels. The study indicated a mean level of reserves equal to 88 years of supply at 2007 production levels. According to the report, shale gas production growth from only the major six shale plays in the U.S., plus the Marcellus shale, could become 27 billion cubic feet per day and as high as 39 billion cubic feet per day by 2015. Navigant has also indicated that development of the shale resources base has resulted in a substantial surplus of natural gas compared to demand of as much as 11 billion cubic feet per day. These current surplus levels are 18% of annual average historical U.S. consumption levels of approximately 20 Tcf per year; providing sufficient gas supply to meet the requirements of all existing markets and to meet new market requirements. Based on analyst reports, we believe that there is a significant worldwide supply of natural gas relative to crude oil as well. According to the 2009 BP Statistical Review of World Energy, on a global basis, the ratio of proven natural gas reserves to 2008 natural gas production was 44% greater than the ratio of proven crude oil reserves to 2008 crude oil production. This analysis suggests significantly greater longer term availability of natural gas than crude oil based on current consumption.

        We believe there will be significant growth in the consumption of natural gas as a vehicle fuel among vehicle fleets, and our goal is to capitalize on this trend and enhance our leadership position as this market expands. We have built natural gas fueling stations, and plan to build additional natural gas fueling stations, that will provide LNG to fleet vehicles at the Ports of Los Angeles and Long Beach and for other regional corridors throughout the United States. We also anticipate expanding our sales of CNG and LNG in the other markets in which we operate, including public transit, regional trucking, refuse hauling and airports. Consistent with the anticipated growth of our business, we also expect that our operating costs and capital expenditures will increase, primarily from the anticipated expansion of our station network or LNG production capacity, as well as the logistics of delivering more CNG and LNG to our customers. We also anticipate that we will continue to seek to acquire assets and/or businesses that are in the natural gas fueling infrastructure or biomethane production business that may require us to raise additional capital. Additionally, we have and will continue to increase our sales and marketing team and other necessary personnel as we seek to expand our existing markets and enter new markets, which will also result in increased costs.

        Continuing high unemployment rates and reduced economic activity may reduce our opportunities to attract new fleet customers. Many governmental entities, which represented approximately 41% of our revenues for the three months ended March 31, 2010, are experiencing significant budget deficits as a result of the economic recession and have been, and may continue to be, unable to invest in new natural gas vehicles for their transit or refuse fleets or may be compelled to reduce public

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transportation and services, or the prices they pay for these services, which would negatively affect our business.

        Sources of liquidity and anticipated capital expenditures.    Liquidity is the ability to meet present and future financial obligations either through operating cash flows, the sale or maturity of existing assets, or by the acquisition of additional funds through capital management. Historically, our principal sources of liquidity have consisted of cash provided by operations and financing activities.

        We anticipate that we will need to raise capital in order to continue to grow our business. Our current business plan assumes that the NAT GAS Act or comparable legislation is passed into law and calls for approximately $76.1 million in capital expenditures from April 1, 2010 through December 31, 2010, primarily related to construction of new fueling stations. We will have to raise capital through debt or equity to fund this business plan if federal legislation is passed into law providing incentives for the use of natural gas fuel and purchase of natural gas vehicles and these incentives lead to rapid growth in our business. If the NAT GAS Act or similar legislation is not passed or any available incentives do not lead to rapid growth in our business, we anticipate that we will build fewer fueling stations and our capital expenditures may be materially less than $76.1 million. Notwithstanding the status of any federal legislation, we may also elect to invest additional amounts in expansion of our California LNG plant, expansion of our DCE landfill gas processing plant, or for other acquisitions or investments in companies or assets in the natural gas fueling infrastructure, services and production industries, including biomethane production. We will need to raise additional capital as necessary to fund any expansion of our California LNG plant or DCE landfill gas plant, acquisitions or other capital expenditures or investments that we cannot fund through available cash, our line of credit from PlainsCapital Bank, or cash generated by operations. The timing and necessity of any future capital raise will depend on our rate of new station construction, which will be affected by any federal legislation that may provide incentives for natural gas vehicle purchases and fuel use, any decision to expand our California LNG plant or DCE gas processing plant and potential merger or acquisition activity. For more information, see "Liquidity and Capital Resources" below. We may not be able to raise capital on terms that are favorable to existing stockholders or at all. Any inability to raise capital may impair our ability to invest in new stations, expand our California LNG plant or DCE gas processing plant, develop natural gas fueling infrastructure and invest in strategic transactions or acquisitions and reduce our ability to grow our business and generate increased revenues.

        Volatility in operating results related to futures contracts.    Historically, we have purchased futures contracts from time to time to help mitigate our exposure to natural gas price fluctuations in current periods and in future periods. Prior to 2008, our futures contracts did not qualify for hedge accounting under the applicable derivative accounting guidance, and in 2008, some of our contracts qualified for hedge accounting under the accounting guidance and some did not. In 2009, all of our futures contracts did qualify for hedge accounting under the accounting guidance. Gains and losses related to the futures contracts that did not qualify for hedge accounting, which appear in the line item derivative (gains) losses in our condensed consolidated financial statements, have materially impacted our results of operations in recent periods. For the years ended December 31, 2006, 2007 and 2008, derivative (gains) losses associated with futures contracts were $78,994,947, $0 and $611,175, respectively. For this reason and others, we caution investors that our past operating results may not be indicative of future results. For more information, please read "Volatility of Earnings and Cash Flows" and "Risk Management Activities" below.

        Volatility in operating results related to Series I warrants.    Beginning January 1, 2009, under new accounting guidance, we are required to record the change in the fair market value of our Series I warrants in our financial statements until the Series I warrants are exercised or expire. If the price of our common stock increases during future periods when our Series I warrants are outstanding, we may be required to recognize material losses based on the valuation of the outstanding Series I warrants. We recognized a (gain) loss of $0.2 million, $2.2 million, $15.4 million, ($0.4) million and $18.6 million

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related to recording the fair market value changes of our Series I warrants in the quarters ended March 31, 2009, June 30, 2009, September 30, 2009, December 31, 2009 and March 31, 2010, respectively. Our earnings or loss per share may be materially impacted by future gains or losses we are required to take as a result of valuing our Series I warrants.

        Volatility in operating results related to BAF contingent consideration    Under new business combination accounting guidance, we are required to record the change in the value of the contingent consideration related to our acquisition of BAF in our financial statements through the contingency period, which expires December 31, 2011. If the anticipated results of BAF increase during future periods, we may be required to recognize material losses based on the valuation of the increased consideration due to the former BAF shareholders. We recognized a loss of $0.3 million related to recording the change in the value of the contingent consideration in the quarter ended March 31, 2010. Our earnings or loss per share may be materially impacted by future gains or losses we are required to take as a result of changes in the contingent consideration amount.

        Business risks and uncertainties.    Our business and prospects are exposed to numerous risks and uncertainties. For more information, see "Risk Factors" in Part II, Item 1A of this report.

Operations

        We generate revenues principally by selling CNG and LNG and providing operations and maintenance services to our vehicle fleet customers. For the three months ended March 31, 2010, CNG and biomethane (together) represented 74% and LNG represented 26% of our natural gas sales (on a gasoline gallon equivalent basis). To a lesser extent, we generate revenues by designing and constructing fueling stations and selling or leasing those stations to our customers. We also generate material revenues through sales of biomethane produced by our joint venture subsidiary DCE, and beginning in the fourth quarter of 2009, sales of natural gas vehicles by our wholly owned subsidiary BAF. Substantially all of our operating and maintenance revenues are generated from CNG stations, as owners of LNG stations tend to operate and maintain their own stations. Substantially all of our station sale and leasing revenues have been generated from CNG stations.

CNG Sales

        We sell CNG through fueling stations located on our customers' properties and through our network of public access fueling stations. At these CNG fueling stations, we procure natural gas from local utilities or brokers under standard, floating-rate arrangements and then compress and dispense it into our customers' vehicles. Our CNG sales are made primarily through contracts with our fleet customers. Under these contracts, pricing is determined primarily on an index-plus basis, which is calculated by adding a margin to the local index or utility price for natural gas. CNG sales revenues based on an index-plus methodology increase or decrease as a result of an increase or decrease in the price of natural gas. We also sell a small amount of CNG under fixed-price contracts. We will continue to offer fixed price contracts as appropriate and consistent with our natural gas hedging policy that was revised in May 2008. Our fleet customers typically are billed monthly based on the volume of CNG sold at a station. The remainder of our CNG sales are on a per fill-up basis at prices we set at the pump based on prevailing market conditions. These customers typically pay using a credit card at the station.

LNG Sales

        We sell substantially all of our LNG to fleet customers, who typically own and operate their fueling stations. We also sell LNG to customers at our two public LNG stations and for non-vehicle use. For the first quarter of 2010, we procured 23% of our LNG from third-party producers, and we produced the remainder of the LNG at our liquefaction plants in Texas and California. For LNG that we purchase from third-parties, we may enter into "take or pay" contracts that require us to purchase

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minimum volumes of LNG at index-based rates. We deliver LNG via our fleet of 58 tanker trailers to fueling stations, where it is stored and dispensed in liquid form into vehicles. We sell LNG principally through supply contracts that are priced on either a fixed-price or index-plus basis. LNG sales revenues based on an index-plus methodology increase or decrease as a result of an increase or decrease in the price of natural gas. We also provided price caps to certain customers on the index component of their index-plus pricing arrangement for certain contracts we entered into on or prior to December 31, 2006. Effective January 1, 2007, we ceased offering price-cap contracts to our customers, but we will continue to perform our obligations under price-cap contracts we entered into before January 1, 2007. We will continue to offer fixed price contracts as appropriate and consistent with our natural gas hedging policy adopted in May 2008. Our LNG contracts provide that we charge our customers periodically based on the volume of LNG supplied.

Government Incentives

        From October 1, 2006 through December 31, 2009, we received a volumetric excise tax credit ("VETC") of $0.50 per gasoline gallon equivalent of CNG and $0.50 per liquid gallon of LNG that we sold as vehicle fuel to certain customers. The tax credit was responsible for a significant amount of our historical revenues. Based on the service relationship we had with our customers, either we or our customers are able to claim the credit. We recorded these tax credits as revenues in our condensed consolidated statements of operations as the credits are fully refundable and do not need to offset tax liabilities to be received. As such, the credits are not deemed income tax credits under the accounting guidance applicable to income taxes. In addition, we believe the credits are properly recorded as revenue because we often incorporate the tax credits into our pricing with our customers, thereby lowering the actual price per gallon we charge them. The tax credit expired on December 31, 2009. Versions of a bill to extend the federal fuel excise tax credit have been passed by the United States House of Representatives and the Senate; however, the bills must successfully undergo a process whereby the two bills are combined into one bill and the resulting bill is signed into law by the President of the United States before becoming effective. We do not know when, if ever, these bills will pass through this process and be signed by the President. If the tax credit is not reinstated or extended, our revenue in future periods will be materially less than it would have been with the tax credit and our ability to attract new customers, or retain old customers, may also be reduced.

Operation and Maintenance

        We generate a portion of our revenue from operation and maintenance agreements for CNG fueling stations where we do not supply the fuel. We refer to this portion of our business as "O&M." At these fueling stations, the customer contracts directly with a local broker or utility to purchase natural gas. For O&M services, we do not sell the fuel itself, but generally charge a per-gallon fee based on the volume of fuel dispensed at the station. We include the volume of fuel dispensed at the stations at which we provide O&M services in our calculation of aggregate gallon equivalents sold.

Station Construction

        We generate a small portion of our revenue from designing and constructing fueling stations and selling or leasing the stations to our customers. For these projects, we act as general contractor or supervise qualified third-party contractors. We charge construction fees or lease rates based on the size and complexity of the project.

Vehicle Acquisition and Finance

        In 2006, we commenced offering vehicle finance services for some of our customers' purchases of natural gas vehicles or the conversion of their existing gasoline or diesel powered vehicles to operate on natural gas. We loan to certain qualifying customers a portion of, and on occasion up to 100%, of the purchase price of their natural gas vehicles. We may also lease vehicles in the future. Where

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appropriate, we apply for and receive state and federal incentives associated with natural gas vehicle purchases and pass these benefits through to our customers. We may also secure vehicles to place with customers or pay deposits with respect to such vehicles prior to receiving a firm order from our customers, which we may be required to purchase if our customer fails to purchase the vehicle as anticipated. Through March 31, 2010, we have not generated significant revenue from vehicle finance activities.

Landfill Gas

        In August 2008, we acquired 70% of the outstanding membership interests of DCE for a purchase price of $19.6 million including transaction costs. DCE owns a facility that collects, processes and sells biomethane from the McCommas Bluff landfill located in Dallas, Texas. From the acquisition date through December 31, 2008, for the year ended December 31, 2009 and for the three months ended March 31, 2010, DCE generated approximately $1.8 million, $7.9 million and $2.8 million, respectively, in revenue from sales of biomethane, all of which is included in our condensed consolidated statements of operations.

        On April 3, 2009, DCE entered into a fifteen year gas sale agreement with Shell Energy North America (US), L.P. ("Shell") for the sale by DCE to Shell of biomethane produced by DCE's landfill gas processing facility.

        DCE retains the right to reserve from the gas sale agreement up to 500 MMBtus per day of biomethane for sale as a vehicle fuel. To the extent that DCE produces volumes of biomethane in excess of the volumes sold under the agreement with Shell, DCE will either attempt to sell such volumes at then-prevailing market prices or seek to enter into another gas sale agreement in the future. There is no guarantee that DCE will produce or be able to sell up to the maximum volumes called for under the agreement, and DCE's ability to produce such volumes of biomethane is dependent on a number of factors beyond DCE's control including, but not limited to, the availability and composition of the landfill gas that is collected, the impact on DCE's operations of the operation of the landfill by the City of Dallas and the reliability of the processing plant's critical equipment. The processing equipment is currently being expanded and upgraded which may result in significant down time to complete the work, which consequently may reduce DCE's sales of biomethane during the expansion and upgrade work.

        The sale price for the gas under the agreement with Shell is fixed and increases in 2010 and 2011. The sale price for the gas represents a substantial premium to the current prevailing prices for natural gas at May 3, 2010.

        Under the terms of the agreement, DCE has retained the rights to any available greenhouse gas emission reduction credits that may be generated through the operation of the landfill gas collection and processing facility, provided that DCE must supply Shell with a sufficient number of such credits to enable the end-user of the gas to meet applicable "net-zero" emissions requirements under the relevant renewable portfolio standard with respect to use of the biomethane in power generation. DCE is in the preliminary stages of assessing whether greenhouse gas emission reduction credits will be generated or available for sale as a result of the landfill gas collection. Given the complex and changing standards and requirements in the market for greenhouse gas emission reduction credits, there can be no guarantee that any greenhouse gas emission credits will be generated or available for sale as a result of DCE's landfill gas operations.

        The gas sale agreement is terminable by either party on 30 days' written notice if the California Energy Commission makes a written determination or adopts a ruling or regulation after the date of the agreement that the biomethane sold under the agreement will, from the date of such ruling or regulation, no longer qualify as a California Renewable Portfolio Standard eligible fuel. In addition, Shell has the right to terminate the agreement upon 30 days' written notice if the volumes of

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biomethane produced and delivered, calculated monthly on a rolling two-year average, are less than an annual average of 630,720 MMBtu per year (or 2,083 MMBtu per day).

Vehicle Conversion

        On October 1, 2009, we purchased all of the outstanding shares of BAF Technologies, Inc. Founded in 1992, BAF provides natural gas vehicle conversions, alternative fuel systems, application engineering, service and warranty support and research and development. BAF's vehicle conversions include taxis, limousines, vans, pick-up trucks and shuttle buses. BAF utilizes advanced natural gas system integration technology and has certified NGVs under both EPA and CARB standards achieving Super Ultra Low Emission Vehicle emissions. We generate revenues through the sale of natural gas vehicles that have been converted to run on natural gas by BAF. The majority of BAF's revenue during 2009 was derived from sales of converted natural gas service vans to AT&T. During the fourth quarter of 2009 and for the three months ended March 31, 2010, BAF contributed approximately $6.9 million and $9.0 million, respectively, to our revenue.

Volatility of Earnings and Cash Flows

        Our earnings and cash flows historically have fluctuated significantly from period to period based on our futures activities, as all but a few of our futures contracts have historically not qualified for hedge accounting under the relevant derivative accounting guidance. We have therefore recorded any changes in the fair market value of these contracts that did not qualify for hedge accounting directly in our statements of operations in the line item derivative (gains) losses along with any realized gains or losses generated during the period. For example, we experienced derivative gains of $5.7 million for the three months ended June 30, 2008, and derivative losses of $6.0 million and $0.3 million for the three months ended September 30, 2008 and December 31, 2008, respectively. We had no derivative gains or losses for the three months ended March 31, 2007, June 30, 2007, September 30, 2007, December 31, 2007, March 31, 2008, March 31, 2009, June 30, 2009, September 30, 2009, December 31, 2009 and March 31, 2010 related to our futures contracts. In accordance with our natural gas hedging policy, we plan to structure all subsequent futures contracts as cash flow hedges under the applicable derivative accounting guidance, but we cannot be certain that they will qualify. See "Risk Management Activities" below. If the futures contracts do not qualify for hedge accounting, we could incur significant increases or decreases in our earnings based on fluctuations in the market value of the contracts from period to period.

        Additionally, we are required to maintain a margin account to cover losses related to our natural gas futures contracts. Futures contracts are valued daily, and if our contracts are in loss positions at the end of a trading day, our broker will transfer the amount of the losses from our margin account to a clearinghouse. If at any time the funds in our margin account drop below a specified maintenance level, our broker will issue a margin call that requires us to restore the balance. Consequently, these payments could significantly impact our cash balances. At March 31, 2010, we had $5.4 million on deposit in margin accounts.

        The decrease in the value of our futures positions and any required margin deposits on our futures contracts that are in a loss position could significantly impact our financial condition in the future.

        Beginning January 1, 2009, under new accounting guidance, we are required to record the change in the fair market value of our Series I warrants in our financial statements. If the price of our common stock increases during future periods when our Series I warrants are outstanding, we may be required to recognize material losses based on the valuation of the outstanding Series I warrants. We recognized a (gain) loss of $0.2 million, $2.2 million, $15.4 million, ($0.4) million, and $18.6 million related to recording the fair market value changes of our Series I warrants in the quarters ended March 31, 2009, June 30, 2009, September 30, 2009, December 31, 2009 and March 31, 2010, respectively (see note 17 to our condensed consolidated financial statements contained elsewhere herein). Our earnings or loss per share may be materially impacted by future gains or losses we are required to take as a result of valuing our Series I warrants.

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        Under new business combination accounting guidance, we are required to record the change in the value of the contingent consideration related to our acquisition of BAF in our financial statements through the contingency period, which expires December 31, 2011. If the anticipated results of BAF increase during future periods, we may be required to recognize material losses based on the valuation of the increased consideration due to the former BAF shareholders. We recognized a loss of $0.3 million related to recording the change in the contingent consideration in the quarter ended March 31, 2010. Our earnings or loss per share may be materially impacted by future gains or losses we are required to take as a result of changes in the contingent consideration amount.

Debt Compliance

        Our credit agreement with PlainsCapital Bank ("PCB") ("Credit Agreement") requires us to comply with certain covenants. We may not incur indebtedness or liens except as permitted by the Credit Agreement, or declare or pay dividends. We must maintain, on a quarterly basis, minimum liquidity of not less than $6.0 million, accounts receivable balances, as defined, of not less than $8.0 million, consolidated net worth, as defined, of not less than $150.0 million, and a debt to equity ratio, as defined, of not more than 0.3 to 1. Beginning in the quarter ended June 30, 2009, we must also maintain a specific minimum debt service ratio at each quarter end. Effective in the fourth quarter of 2008, we established a lock-box arrangement with PCB subject to the Credit Agreement. Funds received from our customers are remitted to the lock-box and then deposited to a PCB bank account. The remitted funds are not used to pay-down the balance of the credit agreement unless there is an event of default on the Credit Agreement. One of the events of default is the occurrence of a "material adverse change," which is a subjective acceleration clause. Based on the relevant accounting guidance, we have classified our debt pursuant to the Credit Agreement as short-term or long-term, as appropriate, and we believe an event of default is more than remote but not more likely than not. If we default on the Credit Agreement, all of the obligations under the Credit Agreement will become immediately due and payable and all funds received in our lockbox held by PCB, plus $2.5 million we have deposited with PCB in a payment reserve account, will be applied to the balance due on the Credit Agreement. One of our bank covenants is a requirement to maintain accounts receivable balances from certain subsidiaries above $8.0 million at each quarter-end. To the extent natural gas prices continue to fall, or our volumes decline, we could violate this covenant in the future. Beginning with the quarter ended June 30, 2009, we are required to maintain a specific minimum debt service ratio. To the extent our operating results do not materialize as planned, we could violate this covenant in the future. In the event we violate either of these covenants, we would seek a waiver from the bank. We were in compliance with all of our covenants at March 31, 2010.

Risk Management Activities

        Our risk management activities, including the revised natural gas hedging policy adopted by our board of directors in February 2007 and revised by our board of directors on May 29, 2008, are discussed in Part II, Item 7 (Management's Discussion and Analysis of Financial Condition and Results of Operation) of our 2009 Annual Report on Form 10-K.

Critical Accounting Policies

        For the first three months of 2010, there were no material changes to the "Critical Accounting Policies" discussed in Part II, Item 7 (Management's Discussion and Analysis of Financial Condition and Results of Operations) of our 2009 Annual Report on Form 10-K.

Recently Issued Accounting Pronouncements

        For a description of recently issued accounting pronouncements, see note 17 to our condensed consolidated financial statements contained elsewhere herein.

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Results of Operations

        The following is a more detailed discussion of our financial condition and results of operations for the periods presented:

Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2009

        Revenue.    Revenue increased by $8.8 million to $39.0 million in the three months ended March 31, 2010, from $30.2 million in the three months ended March 31, 2009. A portion of this increase was the result of an increase in the number of gallons delivered from 18.3 million gasoline gallon equivalents to 28.6 million gasoline gallon equivalents. The increase in volume was partly from an increase in CNG sales of 7.1 million gallons and an increase in biomethane sales (our 70% share of the biomethane sales of DCE) of 1.0 million gallons. The acquisition of four compressed natural gas operations and maintenance services contracts in May and June of 2009, six new refuse customers, and one new transit customer together accounted for 6.4 million gallons of the CNG volume increase. We also experienced an increase of 2.2 million gallons in LNG volume between periods, which was primarily due to the volume growth of 1.4 million gallons from our existing transit, refuse and industrial customers, combined with 0.8 million gallons from our port trucking customers. Revenue also increased by $9.0 million between periods from sales of natural gas vehicle equipment by BAF, which we acquired on October 1, 2009. These increases were offset by the decrease in our effective price per gallon that we charged to our customers between periods. Our effective price per gallon was $1.04 in the three months ended March 31, 2010, which represents a $0.10 per gallon decrease from $1.14 in the three months ended March 31, 2009. The decrease was primarily due to the acquisition of four compressed

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natural gas operation and maintenance services contracts in May and June of 2009, which are O&M agreements that generate less revenue per gallon than contracts where we supply the natural gas commodity. We also experienced a $5.0 million decrease in station construction revenue between periods and we did not record any revenue related to fuel tax credits in the first quarter of 2010 as the fuel tax credits expired on December 31, 2009. We recorded $4.1 million of revenue related to fuel tax credits in the first quarter of 2009.

        Cost of sales.    Cost of sales increased by $6.0 million to $27.6 million in the three months ended March 31, 2010, from $21.6 million in the three months ended March 31, 2009. Our cost of sales primarily increased between periods as a result of delivering more volume to our customers together with $6.4 million of increased costs related to BAF's vehicle equipment sales, which we began to recognize on October 1, 2009 when we acquired the company. These increases were offset by the decrease in our effective cost per gallon of $0.19 per gallon, to $0.74 per gallon, in the three months ended March 31, 2010. This decrease was primarily the result of the four compressed natural gas operation and maintenance services contracts that we acquired in May and June of 2009 that are included in our volume totals but do not increase our cost of sales amount significantly as we do not pay for the natural gas consumed at the properties. We also experienced a $4.6 million decrease in station construction costs between periods.

        Selling, general and administrative.    Selling, general and administrative expenses increased by $2.0 million to $13.6 million in the three months ended March 31, 2010, from $11.6 million in the three months ended March 31, 2009. The increase was primarily the result of our salaries and benefits amount increasing by $1.3 million between periods as we increased our employee headcount from 138 at March 31, 2009 to 267 at March 31, 2010. In addition, our travel and entertainment expenses increased $0.4 million between periods, primarily due to increased travel of our sales team. We also recognized a charge of $0.3 million during the first quarter of 2010 related to increasing our contingent consideration related to our BAF acquisition. Offsetting these increases was a decrease of $0.5 million between periods related to our stock based compensation expense.

        Depreciation and amortization.    Depreciation and amortization increased by $1.4 million to $5.0 million in the three months ended March 31, 2010, from $3.6 million in the three months ended March 31, 2009. This increase was primarily due to additional depreciation expense in the three months ended March 31, 2010 related to increased property and equipment balances between periods, including our expanded station network. Our March 31, 2010 amortization amount also includes amortization of the intangible assets we obtained in connection with our acquisition of the operation and maintenance contracts we acquired during the second quarter of 2009 and BAF in the fourth quarter of 2009.

        Derivative loss.    Derivative loss increased by $18.4 million to $18.6 million in the three months ended March 31, 2010, from $0.2 million in the three months ended March 31, 2009. The increase represents the increased amount of our mark-to-market accounting on our Series I warrants (see notes 16 and 17 to our condensed consolidated financial statements contained elsewhere herein) during the three month period ended March 31, 2010.

        Interest income (expense), net.    Interest income (expense), net, increased by $141,000 to $109,000 of income for the three months ended March 31, 2010. This increase was primarily the result of a decrease in interest expense in the three months ended March 31, 2010 due to the repayment of our Facility A Loan during the fourth quarter of 2009.

        Other income (expense), net.    There was no significant change in other income (expense), net, between the three months ended March 31, 2010 and the three months ended March 31, 2009.

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        Income from equity method investment.    Income from equity method investment increased by $60,000 to a $77,000 gain for the three months ended March 31, 2010 related to our 49% interest in our Peruvian joint venture.

        Loss of noncontrolling interest.    During the three months ended March 31, 2009 and 2010, we recorded $386,000 and $16,000, respectively, for the noncontrolling interest in the net loss of DCE. The noncontrolling interest represents the 30% interest of our joint venture partner.

Seasonality and Inflation

        To some extent, we experience seasonality in our results of operations. Natural gas vehicle fuel amounts consumed by some of our customers tends to be higher in summer months when buses and other fleet vehicles use more fuel to power their air conditioning systems. Natural gas commodity prices tend to be higher in the fall and winter months due to increased overall demand for natural gas for heating during these periods.

        Since our inception, inflation has not significantly affected our operating results. However, costs for construction, repairs, maintenance, electricity and insurance are all subject to inflationary pressures and could affect our ability to maintain our stations adequately, build new stations, build new LNG plants and expand our existing facilities or materially increase our operating costs.

Liquidity and Capital Resources

        Historically, our principal sources of liquidity have consisted of cash provided by operations and financing activities. In May 2007, we completed our initial public offering of 10,000,000 shares of common stock at a public offering price of $12.00 per share. Net cash proceeds from the initial public offering were approximately $108.5 million, after deducting underwriting discounts, commissions and offering expenses. On August 15, 2008, in connection with our acquisition of 70% of the membership interests of DCE, we entered into a credit agreement with PCB pursuant to which we borrowed $18.0 million under a term loan and an additional $12.0 million under a line of credit (see note 9 to the accompanying condensed consolidated financial statements). On September 24, 2008, we sold 319,488 shares of our common stock at a price of $15.65 per share to Boone Pickens Interests, Ltd. for proceeds of approximately $5.0 million. On November 3, 2008, we sold 4,419,192 units of common stock and warrants for $7.92 per unit and we raised net proceeds of approximately $32.5 million after deducting offering costs. On July 1, 2009, we sold 9,430,000 shares of our common stock to third party investors and received net proceeds of $73.2 million. On October 7, 2009, we repaid the $18.0 million term loan with PCB and simultaneously amended the Credit Agreement and extended a $20 million line of credit ("LOC") to us. The LOC expires August 15, 2010, but we have a one year renewal option we can exercise as long as we are not in default on the PCB debt facilities. As of March 31, 2010, we have not drawn any loan amounts under the new LOC and we have an outstanding balance of $9.9 million on our original line of credit.

        In addition to funding operations, our principal uses of cash have been, and are expected to be, the construction of new fueling stations, construction of LNG production facilities, the purchase of new LNG tanker trailers, investment in biomethane production, the financing of natural gas vehicles for our customers and general corporate purposes, including making deposits to support our derivative activities, geographic expansion (domestically and internationally), expanding our sales and marketing activities, support of legislative initiatives and for working capital for our expansion. We have also acquired and may continue to seek to acquire and invest in companies or assets in the natural gas and biomethane fueling infrastructure, services and production industries. We financed our operations in the first three months of 2010 primarily through cash on hand and cash provided by financing activities.

        At March 31, 2010, we had total cash and cash equivalents of $66.3 million, compared to $67.1 million at December 31, 2009.

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        Cash used in operating activities was $1.0 million for the three months ended March 31, 2010, compared to cash provided by operating activities of $1.7 million for the three months ended March 31, 2009. The decrease in operating cash flow resulted primarily from changes in working capital balances due to timing differences related to various cash flows between periods.

        Cash used in investing activities was $8.8 million for the three months ended March 31, 2010, compared to $9.7 million for the three months ended March 31, 2009. Our purchases of property and equipment were $8.8 million during the first three months of 2010, compared to $9.1 million for the same period in 2009. We made an additional investment during the first three months of 2009 of $0.6 million in the Vehicle Production Group, LLC ("VPG"), a company developing a CNG taxi and a paratransit vehicle. We did not make any additional investment in VPG during the first three months of 2010.

        Cash provided by financing activities for the three months ended March 31, 2010 was $9.0 million, compared to $2.7 million for the three months ended March 31, 2009. This increase is primarily due to the exercise of stock options during the first quarter of 2010, from which we received net proceeds of $9.2 million. In February 2009, we borrowed an additional $3.1 million from PlainsCapital Bank to fund capital expenditures for DCE's landfill plant upgrade.

        Our financial position and liquidity are, and will be, influenced by a variety of factors, including our ability to generate cash flows from operations, deposits and margin calls on our futures positions, the level of any outstanding indebtedness and the interest we are obligated to pay on this indebtedness, our capital expenditure requirements (which consist primarily of station construction, LNG plant construction costs, DCE plant construction costs and the purchase of LNG tanker trailers and equipment) and any merger or acquisition activity.

Capital Expenditures

        Our current business plan, assuming passage of the NAT GAS Act or comparable legislation providing incentives for natural gas vehicle purchases or fuel use, calls for approximately $76.1 million in additional capital expenditures from April 1, 2010 through the end of 2010, primarily related to construction of new fueling stations.

        We anticipate that we will need to raise capital to continue to fund our business. We will have to raise capital to fund our current business plan if the NAT GAS Act or similar legislation is passed into law providing incentives for natural gas fuel use and purchase of natural gas vehicles and it leads to rapid growth in our business. If the NAT GAS Act or similar legislation is not passed, or the incentives do not lead to rapid growth in our business, we anticipate that we will build fewer fueling stations and our capital expenditures may be materially less than $76.1 million. Notwithstanding the outcome of any federal legislation that may lead to growth in our business, if we have significant unanticipated capital expenditures, investments, acquisitions or operating expenses, we may also seek to raise capital to fund such capital expenditures, investments, acquisitions or expenses. We may not be able to raise capital on terms that are favorable to existing stockholders or at all. Any inability to raise capital may impair our ability to invest in new stations, develop natural gas fueling infrastructure, invest in our biomethane business, and invest in strategic transactions or acquisitions and reduce our ability to generate increased revenues.

        Our credit agreement with PCB requires that we comply with certain covenants, as detailed in footnote 9 of our condensed consolidated financial statements contained elsewhere herein. One of the covenants requires that we maintain accounts receivable balances from certain subsidiaries above $8.0 million at each quarter-end during the term. To the extent natural gas prices fall, which would result in decreased revenues, or our volumes sold decline, we could violate this covenant. Also, beginning with the quarter ending June 30, 2009, we are required to maintain a debt service ratio, as defined, of 1.5 to 1. Should our operating results not materialize as planned, we could violate this

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covenant. If we were to violate a covenant, we would seek a waiver from the bank, which the bank is not obligated to grant. If the bank does not grant a waiver, all of the obligations under the credit agreement will become immediately due and payable and $2.5 million of our funds held by PCB would be applied to the balance due on the PCB loans. We also would be unable to use the $20 million PCB line of credit if this were to occur. We were in compliance with all of the covenants as of March 31, 2010.

Contractual Obligations

        The following represents the scheduled maturities of our contractual obligations as of March 31, 2010:

Off-Balance Sheet Arrangements

        At March 31, 2010, we had the following off-balance sheet arrangements that had, or are reasonably likely to have, a material effect on our financial condition.

•

outstanding surety bonds for construction contracts and general corporate purposes totaling $10.0 million,



•

two take-or-pay contract for the purchase of LNG,



•

operating leases where we are the lessee,



•

operating leases where we are the lessor and owner of the equipment, and



•

firm commitments to sell CNG and LNG at fixed prices.

        We provide surety bonds primarily for construction contracts in the ordinary course of business, as a form of guarantee. No liability has been recorded in connection with our surety bonds as we do not believe, based on historical experience and information currently available, that it is probable that any amounts will be required to be paid under these arrangements for which we will not be reimbursed.

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        We have entered into two contracts that require us to purchase minimum volumes of LNG. One contract expires in June 2011, and the other contract expires in October 2017.

        We have entered into operating lease arrangements for certain equipment and for our office and field operating locations in the ordinary course of business. The terms of our leases expire at various dates through 2016. Additionally, in November 2006, we entered into a ground lease for 36 acres in California on which we built our California LNG liquefaction plant. The lease is for an initial term of thirty years and requires payments of $230,000 per year, plus up to $130,000 per year for each 30 million gallons of production capacity utilized, subject to future adjustment based on consumer price index changes. We must also pay a royalty to the landlord for each gallon of LNG produced at the facility, as well as for certain other services that the landlord will provide. Commercial operations began December 1, 2008, and the payments for this lease are included in "Operating lease commitments" in the "Contractual Obligations" table set forth above.

        We are also the lessor in various leases with our customers, whereby our customers lease from us certain stations and equipment that we own.

Item 3.—Quantitative and Qualitative Disclosures about Market Risk

        Commodity Risk    We are subject to market risk with respect to our sales of natural gas, which has historically been subject to volatile market conditions. Our exposure to market risk is heightened when we have a fixed price or price cap sales contract with a customer that is not covered by a futures contract, or when we are otherwise unable to pass through natural gas price increases to customers. Natural gas prices and availability are affected by many factors, including weather conditions, overall economic conditions and foreign and domestic governmental regulation and relations.

        Natural gas costs represented 42% (or 44% excluding BAF) of our cost of sales for 2009 and 41% (or 54% excluding BAF) of our cost of sales for the three month ended March 31, 2010. Prices for natural gas over the ten-year and three-month period from December 31, 1999 through March 31, 2010, based on the NYMEX daily futures data, have ranged from a low of $1.65 per Mcf to a high of $19.38 per Mcf. At March 31, 2010, the NYMEX index price of natural gas was $4.81 per Mcf.

        To reduce price risk caused by market fluctuations in natural gas, we may enter into exchange traded natural gas futures contracts. These arrangements also expose us to the risk of financial loss in situations where the other party to the contract defaults on its contract or there is a change in the expected differential between the underlying price in the contract and the actual price of natural gas we pay at the delivery point.

        We account for these futures contracts in accordance with the accounting guidance on derivatives. The accounting under this guidance for changes in the fair value of a derivative depends upon whether it has been specified in a hedging relationship and, further, on the type of hedging relationship. To qualify for designation in a hedging relationship, specific criteria must be met and appropriate documentation maintained. Our futures contracts did not qualify for hedge accounting under this guidance for the years ended December 31, 2005 and 2006, and we did not have any derivative activity in 2007. Consequently, any changes in the fair value of the derivatives during 2005 and 2006 were recorded directly to our consolidated statements of operations. In 2008, we had certain contracts that did not qualify for hedge accounting and we had two derivative contracts to hedge two fixed supply contracts that did qualify for hedge accounting. During 2009 and the three month period ended March 31, 2010, we had five futures contracts that did qualify for hedge accounting.

        The fair value of the futures contracts we use is based on quoted prices in active exchange traded or over the counter markets which are then discounted to reflect the time value of money for contracts applicable to future periods. The fair value of these futures contracts is continually subject to change due to market conditions. In an effort to mitigate the volatility in our earnings related to futures

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activities, in February 2007, our board of directors adopted a revised natural gas hedging policy which restricts our ability to purchase natural gas futures contracts and offer fixed price sales contracts to our customers. This policy was further revised by our board of directors in May 2008. We plan to structure prospective futures contracts so that they will be accounted for as cash flow hedges under this guidance, but we cannot be certain they will qualify. For more information, please read "—Risk Management Activities" above.

        We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to the futures contracts we hold as of March 31, 2010 to hedge the fixed price component of certain supply contracts. If the price of natural gas were to fluctuate (increase or decrease) by 10% from the price quoted on NYMEX on March 31, 2010 ($4.81 per Mcf), we could expect a corresponding fluctuation in the value of the contracts of approximately $1.6 million.

Item 4.—Controls and Procedures

Disclosure Controls and Procedures

        We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. We carried out an evaluation, under the supervision of and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report.

Changes in Internal Control over Financial Reporting

        There were no changes in our internal control over financial reporting that occurred during the period covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II.—OTHER INFORMATION

Item 1.—Legal Proceedings

        We may become party to various legal actions that arise in the ordinary course of our business. During the course of our operations, we are also subject to audit by tax authorities for varying periods in various federal, state, local, and foreign tax jurisdictions. Disputes have and may continue to arise during the course of such audits as to facts and matters of law. It is impossible at this time to determine the ultimate liabilities that we may incur resulting from any lawsuits, claims and proceedings, audits, commitments, contingencies and related matters or the timing if these liabilities, if any. If these matters were to be ultimately resolved unfavorably, an outcome not currently anticipated, it is possible that such outcome could have a material adverse effect upon our consolidated financial position or results of operations. However, we believe that the ultimate resolution of such actions will not have a material adverse affect on our consolidated financial position, results of operations, or liquidity.

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Item 1A.—Risk Factors

        An investment in our company involves a high degree of risk of loss. You should carefully consider the risk factors discussed below together with the risk factors in Part I, Item 1A of our 2009 Annual Report on Form 10-K and all of the other information included in this report before you decide to purchase shares of our common stock. We believe the risks and uncertainties described below are the most significant we face. The occurrence of any of the following risks could harm our business. In that case, the trading price of our common stock could decline. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also impair our operations.

We have a history of losses and may incur additional losses in the future.

        For the three month period ended March 31, 2010, we incurred pre-tax losses of $25.6 million, which included derivative losses of $18.6 million related to marking to market the value of our Series I warrants. In 2007, 2008 and 2009 we incurred pre-tax losses of $7.7 million, $44.3 million, and $33.4 million, respectively. Our loss for 2008 includes $18.6 million in expenses associated with our support for Proposition 10, the California Alternative Fuel Vehicles and Renewable Energy ballot initiative and our loss for 2009 includes $17.4 million of derivative losses related to marking to market the value of our Series I warrants. During 2007, 2008 and 2009, our losses were substantially decreased by our receipt of approximately $17.0 million, $17.2 million and $15.5 million of revenue from federal fuel tax credits; however, the law providing for the fuel tax credits expired on December 31, 2009. In order to execute our strategy and improve our financial performance, we must continue to invest in developing the natural gas vehicle fuel market and offer our customers compelling natural gas fuel prices. If our natural gas sales activities and station operations do not achieve or maintain profitability that can be sustained in the absence of federal fuel tax credits, our business will suffer and the price of our common stock may drop. In addition, if the price of our common stock increases during future periods when our Series I warrants are outstanding, we may be required to recognize material losses based on the valuation of the outstanding Series I warrants.

A material portion of our historical revenues are associated with a federal fuel excise tax credit that expired on December 31, 2009 and the legislation to extend the federal fuel excise tax credit must successfully pass through the reconciliation process and be signed into law by the President of the United States to go into effect.

        The federal excise tax credit of $0.50 per gasoline gallon equivalent of CNG and liquid gallon of LNG sold for vehicle fuel use, which began on October 1, 2006, expired December 31, 2009 and the legislation to extend this tax credit must successfully pass through the reconciliation process and be signed by the President of the United States in order to become law. Versions of a bill to extend the federal fuel excise tax credit have been passed by the United States House of Representatives and the Senate; however, the bills must successfully undergo a process whereby the two bills are combined into one bill and the resulting bill is signed into law by the President of the United States before becoming effective. We do not know when, if ever, these bills will pass through this process and be signed by the President. Based on the service relationship we have with our customers, either we or our customers were able to claim the credit. In 2007, 2008 and 2009, we recorded approximately $17.0 million, $17.2 million and $15.5 million of revenue, respectively, related to fuel tax credits, representing approximately 14.5%, 13.7% and 11.8%, respectively, of our total revenue during the periods. If the fuel tax credit is not reinstated during 2010 or extended to future periods, our revenue during 2010 and any such future periods will be materially reduced and our financial performance will suffer. Analysts that write research on our company may also reduce their ratings or make negative adjustments to their future expectations of our financial performance if the fuel excise tax credit is not reinstated or extended to future periods, which may also result in a decrease in the price of our common stock.

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In the event that the NAT GAS Act passes, we may need to raise debt or equity capital to fund capital expenditures included in our 2010 capital budget.

        Our capital expenditure budget for 2010 anticipates substantial capital investment in the event that federal legislation providing incentives for the production and use of natural gas vehicles known as the NAT GAS Act, or HR 1835 (the New Alternative Transportation to Give Americans Solutions Act), is successfully passed into law. If this legislation or other similar federal legislation providing substantial incentives for the sale and use of natural gas vehicles is passed by the United States House of Representatives and Senate and signed into law by the President, we anticipate that will need to raise capital to make the capital investments required to build the natural gas fueling infrastructure to meet anticipated demand. Our 2010 capital plan, assuming the passage of the NAT GAS Act or legislation providing for similar incentives, anticipates $76.1 million of capital expenditures from April 1, 2010 through the end of the year, and as of March 31, 2010, we have $66.3 million in cash and $20.0 million in credit available under our line of credit from PlainsCapitalBank. If the NAT GAS Act is passed into law and we are unable to raise sufficient capital to make the investments called for under our 2010 capital budget, our ability to increase revenues through growth in customers and sales will be reduced and competitors may be successful in capturing growth in the natural gas fueling business that is incentivized by the NAT GAS Act.

We may need to raise debt or equity capital to fund unanticipated expenses, capital expenditures, mergers and acquisitions or strategic investments.

        If the NAT GAS Act or similar legislation is not passed into law, we may nevertheless be required to raise debt or equity capital to fund unanticipated expenses, capital expenditures, mergers, acquisitions or strategic investments. Equity or debt financing options may not be available on terms favorable to us or at all, particularly if there are no effective federal incentives supporting the growth of the natural gas fueling business. Additional sales of our common stock or securities convertible into our common stock will dilute existing stockholders and may result in a decline in our stock price. We may also pursue debt financing options including, but not limited to, equipment financing, the sale of convertible promissory notes or commercial bank financing. Recent economic turmoil and severe lack of liquidity in the debt capital markets and volatility and rapidly falling prices in the equity capital markets have severely and adversely affected capital raising opportunities. If we are unable to obtain debt or equity financing in amounts sufficient to fund any unanticipated expenses, capital expenditures, mergers, acquisitions or strategic investments, we will be forced to suspend or curtail these capital expenditures or postpone or delay potential acquisitions or other strategic transactions, which could harm our business, results of operations, and future prospects.

Our growth depends in part on tax and related government incentives for clean burning fuels and alternative fuel vehicles. A reduction in these incentives or the failure to pass new legislation with new incentive programs will increase the cost of natural gas fuel and vehicles for our customers and will significantly reduce our revenue.

        Our business depends in part on tax credits, rebates and similar federal, state and local government incentives that promote the use of natural gas as a vehicle fuel in the United States. The federal fuel excise tax credit for the sale of natural gas fuel expired on December 31, 2009. Versions of a bill to extend the federal fuel excise tax credit have been passed by the United States House of Representatives and the Senate; however, the bills must successfully undergo a process whereby the two bills are combined into one bill and the resulting bill is signed into law by the President of the United States before becoming effective. We do not know when, if ever, these bills will pass through this process and be signed by the President. The federal income tax credit that is available to offset 50% to 80% of the incremental cost of purchasing new or converted natural gas vehicles is scheduled to expire on December 31, 2010, and if these tax credits are not extended, it will have a detrimental effect on the

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natural gas vehicle industry, including sales at our wholly owned subsidiary, BAF Technologies, Inc., and adversely affect our results of operations and financial performance. Our business plan and the ability of our business to successfully grow depends in part on the reinstatement and extension of the federal fuel excise tax credit for natural gas vehicle fuel, the extension of the federal income tax credit for the purchase of natural gas vehicles and the passage of legislation providing for additional incentives for the sale and use of natural gas vehicles, such as the NAT GAS Act. If existing federal incentives are not reinstated or extended and if new incentive programs like the NAT GAS Act are not passed, fewer natural gas vehicles will be sold and used and our revenue and financial performance will be adversely affected. In addition, if grant funds are no longer available under existing government programs for the purchase and construction of natural gas vehicles and stations, the purchase of or conversion to natural gas vehicles and station construction could slow and our business and results of operations will be adversely affected. Continued reduction in tax revenues associated with high unemployment rates, economic recession or slow-down could result in a significant reduction in funds available for government grants that support vehicle conversion and station construction, which could impair our ability to grow our business.

Automobile and engine manufacturers produce very few originally manufactured natural gas vehicles and engines for the U.S. and Canadian markets, which may restrict our sales.

        Limited availability of natural gas vehicles restricts their wide scale introduction and narrows our potential customer base. Original equipment manufacturers produce a small number of natural gas engines and vehicles, and they may not make adequate investments to expand their natural gas engine and vehicle product lines. For the North American market, there is only one major automobile manufacturer that makes natural gas powered passenger vehicles, and major manufacturers of medium and heavy duty vehicles produce only a narrow range and number of natural gas vehicles. In addition, the only natural gas vehicle engine designed for Class 8 trucks available in North America is not certified by the EPA for 2010 emission standards, and therefore cannot be sold until the EPA certification is obtained. The technology utilized in some of the heavy duty vehicles that run on LNG is also relatively new and has not been previously deployed or used in large numbers of vehicles. As a result, these vehicles may require servicing and further technology refinements to address performance issues that may occur as vehicles are deployed in large numbers and are operated under strenuous conditions. If potential heavy duty LNG truck purchasers are not satisfied with truck performance, the existing Class 8 natural gas engines are not 2010 certified or additional heavy duty truck engine manufacturers do not enter the market for LNG engines, it may delay, impair, or eliminate the growth of our LNG fueling business, which would impair our financial performance. Further, North American car and truck manufacturers are facing significant economic challenges that may make it difficult or impossible for them to introduce new natural gas vehicles in the North American market or continue to manufacture and support the limited number of available natural gas vehicles. Due to the limited supply of natural gas vehicles, our ability to promote natural gas vehicles and our natural gas fuel sales may be restricted, even if there is demand.

Decreases in the price of oil, gasoline and diesel fuel without similar decreases in the price of natural gas may slow the growth of our business and negatively impact our financial results.

        Prices for oil, gasoline and diesel fuel have declined substantially from the recent high prices reached in the summer of 2008. The price of a barrel of crude oil has declined from a high of $148.35 per barrel reached on July 11, 2008 to a price of $83.76 per barrel on March 31, 2010. Average retail prices for ultra low sulfur diesel fuel in California have declined from a high of $5.03 in May and June 2008 to $3.07 per gallon at March 31, 2010, and average retail prices for gasoline in California have declined from a high of $4.59 per gallon in June 2008 to $3.09 per gallon at March 31, 2010. The decrease in the price of diesel and gasoline, in particular, has resulted in reduced interest in alternative fuels such as LNG and CNG. Decreased interest in alternative fuels will slow the growth of our

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business. In addition, to the extent that we price our CNG and LNG fuel at a discount to these reduced diesel or gasoline prices in an effort to attract new and retain existing customers, our profit margin on fuel sales may be harmed and our financial results negatively impacted. Our retail prices for LNG fuel in California decreased from $3.70 per diesel gallon equivalent in June and July of 2008 to $2.30 per diesel gallon equivalent at March 31, 2010, and our retail prices for CNG fuel sold in the Los Angeles Basin decreased from a high of $3.30 per gasoline gallon equivalent in July of 2008 to $2.50 per gasoline gallon equivalent at March 31, 2010. Lower fuel prices for CNG and LNG as a result of lower natural gas commodity prices also will reduce our revenues.

If the prices of CNG and LNG do not remain sufficiently below the prices of gasoline and diesel, potential fleet customers will have less incentive to purchase natural gas vehicles, which would decrease demand for CNG and LNG and limit our growth.

        Natural gas vehicles cost more than comparable gasoline or diesel powered vehicles because converting a vehicle to use natural gas adds to its base cost. If the prices of CNG and LNG do not remain sufficiently below the prices of gasoline or diesel, fleet operators may be unable to recover the additional costs of acquiring or converting to natural gas vehicles in a timely manner, and they may choose not to use natural gas vehicles. Our ability to offer CNG and LNG fuel to our customers at lower prices than gasoline and diesel depends in part on natural gas prices remaining lower, on an energy equivalent basis, than oil prices. If the price of oil declines and the price of natural gas increases, it will make it more difficult for us to offer our customers discounted prices for CNG and LNG as compared to gasoline and diesel prices and maintain an acceptable margin on our sales. Recent and significant volatility in oil and gasoline prices demonstrate that it is difficult to predict future transportation fuel costs. In addition, any new regulations imposed on natural gas extraction in the United States, particularly on extraction of natural gas from shale formations, could increase the costs of domestic gas production or make it unprofitable to produce natural gas in the United States, which could lead to substantial increases in the price of natural gas. Reduced prices for gasoline and diesel fuel and continuing uncertainty about fuel prices, combined with higher costs for natural gas and natural gas vehicles, may cause potential customers to delay or reject converting their fleets to run on natural gas. In that event, our sales of natural gas fuel and vehicles would be slowed and our business would suffer.

The volatility of natural gas prices could adversely impact the adoption of CNG and LNG vehicle fuel and our business.

        In the recent past, the price of natural gas has been volatile, and this volatility may continue. From the end of 1999 through March 31, 2010, the price for natural gas, based on the NYMEX daily futures data, ranged from a low of $1.65 per Mcf to a high of $19.38 per Mcf. As of March 31, 2010, the NYMEX index price for natural gas was $4.81 per Mcf. Increased natural gas prices affect the cost to us of natural gas and will adversely impact our operating margins in cases where we have committed to sell natural gas at a fixed price without an effective futures contract in place that fully mitigates the price risk or where we otherwise cannot pass on the increased costs to our customers. In addition, higher natural gas prices may cause CNG and LNG to cost as much as or more than gasoline and diesel generally, which would adversely impact the adoption of CNG and LNG as a vehicle fuel. Conversely, lower natural gas prices reduce our revenues due to the fact that in a significant amount of our customer agreements the commodity cost is passed through to the customer. Among the factors that can cause price fluctuations in natural gas prices are changes in domestic and foreign supplies of natural gas, domestic storage levels, crude oil prices, the price difference between crude oil and natural gas, price and availability of alternative fuels, weather conditions, level of consumer demand, economic conditions, price of foreign natural gas imports, and domestic and foreign governmental regulations and political conditions. In particular, there have been recent legislative efforts to place new regulatory requirements on the production of natural gas by hydraulic fracturing of shale gas reservoirs. Hydraulic

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fracturing of shale gas reservoirs has resulted in a substantial increase in the proven natural gas reserves in the United States, and any change in regulations that makes it substantially more expensive or unprofitable to produce natural gas through hydraulic fracturing could lead to increased natural gas prices. The recent economic recession and increased domestic natural gas supplies have contributed to significant declines in the price of natural gas since the summer of 2008.

Our growth depends in part on environmental regulations and programs mandating the use of cleaner burning fuels, and modification or repeal of these regulations may adversely impact our business.

        Our business depends in part on environmental regulations and programs in the United States that promote or mandate the use of cleaner burning fuels, including natural gas for vehicles. In particular, the Ports of Los Angeles and Long Beach have adopted the San Pedro Bay Ports Clean Air Action Plan, which outlines a Clean Trucks Program that calls for the replacement of drayage trucks with trucks that meet certain clean truck standards. Industry participants with a vested interest in gasoline and diesel, many of which have substantially greater resources than we do, invest significant time and money in an effort to influence environmental regulations in ways that delay or repeal requirements for cleaner vehicle emissions. Further, an economic recession may result in the delay, amendment or waiver of environmental regulations or the Clean Trucks Program due to the perception that they impose increased costs on the transportation industry that cannot be absorbed in a contracting economy. For example, the Clean Trucks Program formerly called for the replacement of a set number of drayage trucks with "clean" trucks, but due to economic conditions and other factors, the Clean Trucks Program no longer calls for any specific number of "clean" truck replacements. In addition, many of the clean trucks that have been deployed have been clean diesel trucks which are generally less expensive than LNG trucks. There have also been recent ballot initiatives commenced in the State of California and political support for postponing or delaying California's implementation of AB 32, which is intended to reduce greenhouse gas emissions. CNG, LNG and biomethane vehicle fuel all produce fewer greenhouse gases than gasoline or diesel fuel and the delay or repeal of AB 32, and in particular California's low-carbon fuel standard, could reduce the appeal of natural gas fuel for our customers and reduce our revenue. The delay, repeal or modification of federal or state regulations or programs that encourage the use of cleaner vehicles, and in particular the Clean Trucks Program outlined in the San Pedro Bay Ports Clean Air Action Plan, could also have a detrimental effect on the U.S. natural gas vehicle industry, which, in turn, could slow our growth and adversely affect our business.

The use of natural gas as a vehicle fuel may not become sufficiently accepted for us to expand our business.

        To expand our business, we must develop new fleet customers and obtain and fulfill CNG and LNG fueling contracts from these customers. We cannot guarantee that we will be able to develop these customers or obtain these fueling contracts. Whether we will be able to expand our customer base will depend on a number of factors, including the level of acceptance and availability of natural gas vehicles, the growth in our target markets of fueling station infrastructure that supports CNG and LNG sales and our ability to supply CNG and LNG at competitive prices. The decline in oil, diesel and gasoline prices from the levels they reached during the summer of 2008 has resulted in decreased interest in alternative fuels like CNG and LNG. In addition, the disruption in the capital markets that began in 2008 has reduced the availability of debt financing to support the purchase of CNG and LNG vehicles and investment in CNG and LNG infrastructure. If our potential customers are unable to access credit to purchase natural gas vehicles, it may make it difficult or impossible for them to invest in natural gas vehicle fleets, which would impair the ability of our business to grow.

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We cannot be certain that we will be successful in managing or integrating our recently acquired subsidiary, BAF, with our existing operations.

        On October 1, 2009, we closed our acquisition of 100% of the equity interests of BAF, which is now our wholly owned subsidiary. BAF provides natural gas vehicle conversions, alternative fuel systems, application engineering, service and warranty support and research and development services. Historically, BAF has suffered net operating losses and required outside financing to support its ongoing business. Our ability to realize benefits from the acquisition depends on our ability to improve BAF's financial performance in comparison to its historical financial results. Our management team has limited experience managing a vehicle conversion company and BAF represents a new product offering for our company. The successful management and integration of BAF's operations will present significant challenges, including realizing economies of scale and integrating internal financial and operational systems. We cannot assure you that we will realize any anticipated benefits or will successfully integrate any of the acquired operations with our existing operations. In addition, the BAF operations do not have the disclosure controls and procedures or internal controls over financial reporting that are as thorough or effective as those required for public companies. Although we intend to implement appropriate controls and procedures as we integrate the BAF operations, we cannot provide assurance as to the effectiveness of BAF's disclosure controls and procedures or internal controls over financial reporting until we have fully integrated them.

Failure to comply with the terms of our Credit Agreement with PlainsCapital Bank could impair our rights in DCE and other secured property.

        In August 2008, we acquired a 70% interest in DCE, which manages a biomethane production facility at the McCommas Bluff landfill in Dallas, Texas and holds a lease to the associated landfill gas development rights. We borrowed $18 million from PlainsCapital Bank ("PCB") to fund the acquisition and obtained a $12 million line of credit from PCB to pay certain costs and expenses of the acquisition and finance capital improvements of the gas processing plant through a loan made by us to DCE. We have used $12.0 million of the line of credit from PCB and the outstanding balance was $9.9 million as of March 31, 2010. In October, 2009, we repaid the $18 million loan that we used to fund the acquisition of DCE and amended the Credit Agreement to obtain a $20 million line of credit from PlainsCapital Bank to finance capital expenditures and working capital for our operations and for other general business purposes. As of the date of filing of this Form 10-Q for the three months ending March 31, 2010, we had not borrowed any money under the $20 million line of credit. To secure our obligations under the Credit Agreement, we granted PCB a security interest in 45 of our LNG tanker trailers, certain accounts receivable and inventory, and our note receivable from, and our membership interests in DCE. Our Credit Agreement with PCB requires that we comply with certain covenants. One of the covenants requires that we maintain accounts receivable balances from certain subsidiaries above $8 million at each quarter-end during the term. To the extent natural gas prices fall, which would result in decreased revenues, or our volumes sold decline, we could violate this covenant. Also, beginning with the quarter ending June 30, 2009, we have been required to maintain a specific minimum debt service ratio. Should our operating results not materialize as planned, we could violate this covenant. If we were to violate a covenant, we would seek a waiver from the bank, which the bank is not obligated to grant. If the bank does not grant a waiver, all of the obligations under the Credit Agreement will become immediately due and payable and $2.5 million of our funds held by PCB would be applied to the balance due on the PCB loans. We also would be unable to use the $20 million PCB line of credit if this were to occur.

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The infrastructure to support gasoline and diesel consumption is vastly more developed than the infrastructure for natural gas vehicle fuels.

        Gasoline and diesel fueling stations and service infrastructure are widely available in the United States. For natural gas vehicle fuels to achieve more widespread use in the United States and Canada, they will require a promotional and educational effort and the development and supply of more natural gas vehicles and fueling stations. This will require significant continued effort by us, as well as government and clean air groups, and we may face resistance from oil companies and other vehicle fuel companies. A prolonged economic recession and continued disruption in the capital markets may make it difficult or impossible to obtain financing to expand the natural gas vehicle fueling infrastructure and impair our ability to grow our business. There is no assurance natural gas will ever achieve the level of acceptance as a vehicle fuel necessary for us to expand our business significantly.

We have significant contracts with federal, state and local government entities that are subject to unique risks.

        We have existing, and will continue to seek, long-term LNG and CNG station construction, maintenance and fuel sales contracts with various federal, state and local governmental bodies, which accounted for approximately 64% of our yearly revenues from 2006 through 2009. In May 2009, we spent $5.6 million to acquire four new CNG operation and maintenance contracts with government agencies. In addition to our normal business risks, our contracts with these government entities are often subject to unique risks, some of which are beyond our control. Long-term government contracts and related orders are subject to cancellation if appropriations for subsequent performance periods are not made. The termination of funding for a government program supporting any of our CNG or LNG operations could result in a loss of anticipated future revenues attributable to that program, which could have a negative impact on our operations. In addition, government entities with whom we contract are often able to modify, curtail or terminate contracts with us without prior notice at their convenience, and are only liable for payment for work done and commitments made at the time of termination. Modification, curtailment or termination of significant contracts could have a material adverse effect on our results of operations and financial condition. In particular, if any of the contracts we recently acquired are terminated, we may be unable to recover our investment in acquiring the contracts.

The budget deficits being experienced by many governmental entities may reduce the available funding for certain natural gas programs and services and the purchase of CNG or LNG fuel, which could reduce our revenue and impair our financial performance.

        Many governmental entities are experiencing significant budget deficits as a result of the economic recession, which has and may continue to reduce or curtail their ability to fund natural gas fuel programs, purchase natural gas vehicles or provide public transportation and services, which would harm our business. Our contracts with governmental entities constituted approximately 64% of our revenues from 2006 to 2009. Furthermore, in response to budget deficits, such governmental entities have and may continue to request or demand that we lower our price for CNG or LNG fuel. Since we compete for several of our contracts with government entities through a competitive bidding process, in order to be awarded new contracts or for the renewal of an expired contract, we may have to agree to lower prices for CNG fuel, LNG fuel and our operations and maintenance services. Government deficits, spending reductions and competitive bidding procurement processes could reduce our margins on fuel sales, lower our revenue and impair our financial performance.

Conversion of vehicles to run on natural gas is time-consuming and expensive and may limit the growth of our sales.

        Conversion of vehicle engines from gasoline or diesel to natural gas is performed by only a small number of vehicle conversion suppliers (including our wholly owned subsidiary, BAF) that must meet

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stringent safety and engine emissions certification standards. The engine certification process is time consuming and expensive and raises vehicle costs. In addition, conversion of vehicle engines from gasoline or diesel to natural gas may result in vehicle performance issues or increased maintenance costs that could discourage our potential customers from purchasing converted vehicles that run on natural gas and impair the financial performance of our recently acquired subsidiary, BAF. Without an increase in vehicle conversion options, reduced vehicle conversion costs and improved vehicle conversion performance, our sales of natural gas vehicle fuel and converted natural gas vehicles, through BAF, may be restricted and our revenue will be reduced both by less demand for natural gas vehicle fuel and less demand for converted natural gas vehicles.

A majority of our sales of CNG vehicles are to one customer. If this customer does not continue to purchase CNG vehicles, then revenue at our wholly owned subsidiary, BAF, will decline and our financial results will be impaired.

        During 2009, BAF derived approximately 63% of its revenue from AT&T. During 2010, BAF anticipates that a similar percentage of its revenue will also be derived from sales to AT&T. AT&T is not required to purchase any CNG vehicle conversion kits under its agreement with BAF and the agreement and all purchase orders submitted by AT&T under the agreement may be cancelled by AT&T at any time for any reason. If AT&T does not continue to order and pay for CNG vehicle conversion kits produced by BAF, then BAF's sales revenue will substantially decline and our financial performance may suffer. In the absence of continued sales to AT&T, BAF may require significant capital investment to continue as a going concern, which could drain our capital resources.

If there are advances in other alternative vehicle fuels or technologies, or if there are improvements in gasoline, diesel or hybrid engines, demand for natural gas vehicles may decline and our business may suffer.

        Technological advances in the production, delivery and use of alternative fuels that are, or are perceived to be, cleaner, more cost-effective or more readily available than CNG or LNG have the potential to slow adoption of natural gas vehicles. Advances in gasoline and diesel engine technology, especially hybrids, may offer a cleaner, more cost-effective option and make fleet customers less likely to convert their fleets to natural gas. Technological advances related to ethanol or biodiesel, which are increasingly used as an additive to, or substitute for, gasoline and diesel fuel, may slow the need to diversify fuels and affect the growth of the natural gas vehicle market. In addition, a prototype heavy duty electric truck model was recently introduced at the ports of Los Angeles and Long Beach. Use of electric heavy duty trucks or the perception that electric heavy duty trucks may soon be widely available and provide satisfactory performance in heavy duty applications may reduce demand for heavy duty LNG trucks. In addition, hydrogen and other alternative fuels in experimental or developmental stages may eventually offer a cleaner, more cost-effective alternative to gasoline and diesel than natural gas. Advances in technology that slow the growth of or conversion to natural gas vehicles, or which otherwise reduce demand for natural gas as a vehicle fuel, will have an adverse effect on our business. Failure of natural gas vehicle technology to advance at a sufficient pace may also limit its adoption and our ability to compete with other alternative fuels and alternative fuel vehicles.

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Our ability to supply LNG to new and existing customers is restricted by limited production of LNG and by our ability to source LNG without interruption and near our target markets.

        Production of LNG in the United States is fragmented. LNG is produced at a variety of smaller natural gas plants around the United States, as well as at larger plants. It may become difficult for us to obtain additional LNG without interruption and near our current or target markets at competitive prices. If our LNG liquefaction plants, or any of those from which we purchase LNG, are damaged by severe weather, earthquake or other natural disaster, or otherwise experience prolonged downtime, our LNG supply will be restricted. If we are unable to supply enough of our own LNG or purchase it from third parties to meet existing customer demand, we may be liable to our customers for penalties. Our growth plans, if successful, will require substantial growth in the available LNG supply across the United States, and if this supply is unavailable, it will constrain our ability to grow the market for LNG fuel including supplying LNG fuel to heavy duty truck consumers. An LNG supply interruption or LNG demand that exceeds available supply will also limit our ability to expand LNG sales to new customers and could disrupt our relationship with existing customers, which would hinder our growth. Furthermore, because transportation of LNG is relatively expensive, if we are required to supply LNG to our customers from distant locations and cannot push these costs on to our customers, our operating margins will decrease on those sales due to our increased transportation costs.

LNG supply purchase commitments may exceed demand causing our costs to increase and impact LNG sales margins.

        Two of our LNG supply agreements have a take or pay commitment and our California LNG liquefaction plant has land lease and other fixed operating costs regardless of production and sales levels. The take or pay commitments require us to pay for the LNG that we have agreed to purchase irrespective of whether we can sell the LNG to our own customers. For example, the LNG Sales Agreement that we entered into with Spectrum Energy Services, LLC ("Spectrum") on October 17, 2007 has a ten year term and, provided that Plant Capacity (as defined in the LNG Sales Agreement) is available to be taken by us, the plant is not shut down by Spectrum and no event beyond our reasonable control prevents us from taking delivery of LNG, we are committed to purchasing at least 45,000 gallons of LNG per day. Should the market demand for LNG decline or if we lose significant LNG customers or if demand under any existing or any future LNG supply contract does not maintain its volume levels or grow, overall operating and supply costs may increase as a percentage of revenue and negatively impact our margins.

One of our third-party LNG suppliers may cancel its supply contract with us on short notice or increase its LNG prices, which would hinder our ability to meet customer demand and increase our costs.

        Under certain circumstances, Williams Gas Processing Company ("Williams") may terminate our LNG supply contract with them on short notice. Williams may also significantly increase the price of LNG we purchase upon 24 hours' notice if their costs to produce LNG increases, and we may be required to reimburse them for certain other expenses. Our contract with Williams, which supplied 29% of the LNG we sold for the year ended December 31, 2008, 14% for the year ended December 31, 2009, and 16.1% for the first three months of 2010, expires on June 30, 2011. Furthermore, there are a limited number of LNG suppliers in or near the areas where our LNG customers are located. It may be difficult to replace an LNG supplier, and we may be unable to obtain alternate suppliers at acceptable prices, in a timely manner or at all. If significant supply interruptions occur, our ability to meet customer demand will be impaired, customers may cancel orders and we may be subject to supply interruption penalties. If we are subject to LNG price increases, our operating margins may be impaired and we may be forced to sell LNG at a loss under our LNG supply contracts.

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If we are unable to obtain natural gas in the amounts needed on a timely basis or at reasonable prices, we could experience an interruption of CNG or LNG deliveries or increases in CNG or LNG costs, either of which could have an adverse effect on our business.

        Some regions of the United States and Canada depend heavily on natural gas supplies coming from particular fields or pipelines. Interruptions in field production or in pipeline capacity could reduce the availability of natural gas or possibly create a supply imbalance that increases natural gas prices. We have in the past experienced LNG supply disruptions due to severe weather in the Gulf of Mexico and plant outages. If there are interruptions in field production, insufficient pipeline capacity, equipment failure on liquefaction production or delivery delays, we may experience supply stoppages which could result in our inability to fulfill delivery commitments. This could result in our being liable for contractual damages and daily penalties or otherwise adversely affect our business.

Oil companies and natural gas utilities, which have far greater resources and brand awareness than we have, may expand into the natural gas fuel market, which could harm our business and prospects.

        There are numerous potential competitors who could enter the market for CNG and LNG vehicle fuels. Many of these potential entrants, such as integrated oil companies and natural gas utilities, have far greater resources and brand awareness than we have. Natural gas utilities, particularly in California, continue to own and operate natural gas fueling stations that compete with our stations. If the use of natural gas vehicles and demand for natural gas vehicle fuel increases, these companies may find it more attractive to enter or expand their operations in the market for natural gas vehicle fuels and we may experience increased pricing pressure, reduced operating margins and fewer expansion opportunities.

If we do not have effective futures contracts in place, increases in natural gas prices may cause us to lose money.

        From 2005 to 2008, we sold and delivered approximately 30% of our total gasoline gallon equivalents of CNG and LNG under contracts that provided a fixed price or a price cap to our customers over terms typically ranging from one to three years, and in some cases up to five years. At any given time, however, the market price of natural gas may rise and our obligations to sell fuel under fixed price contracts may be at prices lower than our fuel purchase price if we do not have effective futures contracts in place. This circumstance has in the past and may again in the future compel us to sell fuel at a loss, which would adversely affect our results of operations and financial condition. Commencing with the adoption of our revised natural gas hedging policy in February 2007, our policy has been to purchase futures contracts to hedge our exposure to natural gas price variability related to our fixed price contracts. Such contracts, however, may not be available or we may not have sufficient financial resources to secure such contracts. In addition, under our hedging policy, we may reduce or remove futures contracts we have in place related to these contracts if such disposition is approved in advance by our board of directors and derivative committee. If we are not economically hedged with respect to our fixed price contracts, we will lose money in connection with those contracts during periods in which natural gas prices increase above the prices of natural gas included in our customers' contracts. As of March 31, 2010, we were economically hedged with respect to all four of our fixed price contracts with our customers.

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Our futures contracts may not be as effective as we intend.

        Our purchase of futures contracts can result in substantial losses under various circumstances, including if we do not accurately estimate the volume requirements under our fixed price customer contracts when determining the volumes included in the futures contracts we purchase, or we are required to purchase a futures contract in connection with a bid proposal and ultimately we are not awarded the entire contract or our customer does not fully perform its obligations under the awarded contract. We also could incur significant losses if a counterparty does not perform its obligations under the applicable futures arrangement, the futures arrangement is economically imperfect or ineffective, or our futures policies and procedures are not properly followed or do not work as planned. Furthermore, we cannot assure that the steps we take to monitor our futures activities will detect and prevent violations of our risk management policies and procedures.

A decline in the value of our futures contracts may result in margin calls that would adversely impact our liquidity.

        We are required to maintain a margin account to cover losses related to our natural gas futures contracts. Futures contracts are valued daily, and if our contracts are in loss positions at the end of a trading day, our broker will transfer the amount of the losses from our margin account to a clearinghouse. If at any time the funds in our margin account drop below a specified maintenance level, our broker will issue a margin call that requires us to restore the balance. Payments we make to satisfy margin calls will reduce our cash reserves, adversely impact our liquidity and may also adversely impact our ability to expand our business. Moreover, if we are unable to satisfy the margin calls related to our futures contracts, our broker may sell these contracts to restore the margin requirement at a substantial loss to us. As of March 31, 2010, we had $5.4 million on deposit related to our futures contracts.

If our futures contracts do not qualify for hedge accounting, our net income and stockholders' equity will fluctuate more significantly from quarter to quarter based on fluctuations in the market value of our futures contracts.

        We account for our futures activities under the relevant derivative accounting guidance, which requires us to value our futures contracts at fair market value in our financial statements. Prior to June 2008, our futures contracts have not qualified for hedge accounting, and therefore we have recorded any changes in the fair market value of these contracts directly in our consolidated statements of operations in the line item "derivative (gains) losses" along with any realized gains or losses during the period. Currently, we attempt to qualify all of our futures contracts for hedge accounting under the relevant derivative accounting guidance, but there can be no assurances that we will be successful in doing so. At March 31, 2010, all of our futures contracts qualified for hedge accounting. To the extent that all or some of our futures contracts do not qualify for hedge accounting, we could incur significant increases and decreases in our net income and stockholders' equity in the future based on fluctuations in the market value of our futures contracts from quarter to quarter. We had no derivative gains or losses related to our natural gas futures contracts for the year ended December 31, 2009 and for the three months ended March 31, 2010. Any negative fluctuations may cause our stock price to decline due to our failure to meet or exceed the expectations of securities analysts or investors.

Compliance with potential greenhouse gas regulations affecting our LNG plants or fueling stations may prove costly and negatively affect our financial performance.

        California has adopted legislation, AB 32, or the Global Warming Solutions Act, which calls for a cap on greenhouse gas emissions throughout California and a statewide reduction to 1990 levels by 2020, and an additional 80% reduction below 1990 levels by 2050. Seven western U.S. states (Arizona, California, Montana, New Mexico, Oregon, Utah and Washington) and four Canadian provinces (British Columbia, Manitoba, Ontario and Quebec) formed the Western Climate Initiative to help

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combat climate change. Other states and the federal government are considering passing measures to regulate and reduce greenhouse gas emissions. Any of these regulations, when and if implemented, may regulate the greenhouse gas emissions produced by our LNG production plants in California and Texas or our LNG and CNG fueling stations and require that we obtain emissions credits or invest in costly emissions prevention technology. We cannot currently estimate the potential costs associated with federal or state regulation of greenhouse gas emissions from our LNG plants or LNG and CNG stations, and these unknown costs are not contemplated in the financial terms of our customer agreements. These unanticipated costs may have a negative impact on our financial performance and may impair our ability to fulfill customer contracts at an operating profit.

Natural gas fueling operations and vehicle conversions entail inherent safety and environmental risks that may result in substantial liability to us.

        Natural gas fueling operations and vehicle conversions entail inherent risks, including equipment defects, malfunctions and failures and natural disasters, which could result in uncontrollable flows of natural gas, fires, explosions and other damages. For example, operation of LNG pumps requires special training and protective equipment because of the extreme low temperatures of LNG. LNG tanker trailers have also in the past been, and may in the future be, involved in accidents that result in explosions, fires and other damage. Improper refueling of LNG vehicles can result in venting of methane gas, which is a potent greenhouse gas, and LNG related methane emissions may in the future be regulated by the EPA or by state regulations. Additionally, CNG fuel tanks, if damaged or improperly maintained, may rupture and the contents of the tank may rapidly decompress and result in death or injury. In 2007, a driver of a CNG van in Los Angeles was killed when the previously damaged tanks he was fueling ruptured. These risks may expose us to liability for personal injury, wrongful death, property damage, pollution and other environmental damage. We may incur substantial liability and cost if damages are not covered by insurance or are in excess of policy limits. If CNG or LNG vehicles are perceived to be unsafe, it will harm our growth and negatively affect BAF's ability to sell converted CNG vehicles, which would impair our financial performance.

Our business is heavily concentrated in the western United States, particularly in California and Arizona. Continuing economic downturns in these regions could adversely affect our business.

        Our operations to date have been concentrated in California and Arizona. For the years ended December 31, 2007, 2008 and 2009, sales in California accounted for 40%, 45% and 49% respectively, and sales in Arizona accounted for 20%, 14% and 10%, respectively, of the total amount of gallons we delivered. For the three month period ended March 31, 2010, sales in California and Arizona accounted for 49% and 9%, respectively, of the total amount of gallons we delivered. A decline in the economy in these areas could slow the rate of adoption of natural gas vehicles, reduce fuel consumption or reduce the availability of government grants, any of which could negatively affect our growth.

We provide financing to fleet customers for natural gas vehicles, which exposes our business to credit risks.

        We loan to certain qualifying customers a portion of, and occasionally up to 100%, of the purchase price of natural gas vehicles. We may also lease vehicles to customers in the future. There are risks associated with providing financing or leasing that could cause us to lose money. Some of these risks include: most of the equipment financed consists of vehicles, which are mobile and easily damaged, lost or stolen, there is a risk the borrower may default on payments, we may not be able to bill properly or track payments in adequate fashion to sustain growth of this service, and the amount of capital available to us is limited and may not allow us to make loans required by customers. Some of our customers, such as taxi owners, may depend on the CNG vehicles that we finance or lease to them as their sole source of income, which may make it difficult for us to recover the collateral in a bankruptcy

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proceeding. The continued disruption in the credit markets may further reduce the amount of capital available to us and an economic recession or continued high unemployment rates may increase the rate of default by borrowers, leading to an increase in losses on our loan portfolio. As of March 31, 2010, we had $4.7 million outstanding in loans provided to customers to finance natural gas vehicle purchases.

We may incur losses and use working capital if we are unable to place with customers the natural gas vehicles that we or our business partners order from manufacturers.

        To ensure availability for our customers, from time to time we enter into binding purchase agreements for natural gas vehicles when there is a significant production lead time. Although we attempt to arrange for customers to purchase the vehicles before delivery to us, we may be unable to locate purchasers on a timely basis and consequently may need to take delivery of and title to the vehicles. These purchases would adversely affect our cash reserves until such time as we can sell the vehicles to our customers, and we may be forced to sell the vehicles at a loss. As of March 31, 2010, we had $0.4 million in aggregate deposits outstanding on natural gas vehicles.

Our business is subject to a variety of governmental regulations that may restrict our business and may result in costs and penalties.

        We are subject to a variety of federal, state and local laws and regulations relating to the environment, health and safety, labor and employment and taxation, among others. These laws and regulations are complex, change frequently and have tended to become more stringent over time. Failure to comply with these laws and regulations may result in a variety of administrative, civil and criminal enforcement measures, including assessment of monetary penalties and the imposition of remedial requirements. From time to time, as part of the regular overall evaluation of our operations, including newly acquired operations, we may be subject to compliance audits by regulatory authorities. In addition, any failure to comply with regulations related to the government procurement process at the federal, state or local level or restrictions on political activities and lobbying may result in administrative or financial penalties including being barred from providing services to governmental entities, which accounted for approximately 64% of our yearly revenues from 2006 through 2009.

        In connection with our LNG liquefaction activities and the landfill gas processing facility operated by DCE, we need or may need to apply for additional facility permits or licenses to address storm water or wastewater discharges, waste handling, and air emissions related to production activities or equipment operations. This may subject us to permitting conditions that may be onerous or costly. Compliance with laws and regulations and enforcement policies by regulatory agencies could require us to make material expenditures, which may distract our officers, directors and employees from the operation of our business.

Operational issues, permitting and other factors at DCE's landfill gas processing facility may adversely affect both DCE's ability to supply biomethane and our operating results.

        In August 2008, we acquired our 70% interest in DCE. In April 2009, DCE entered into a 15-year gas sale agreement with Shell for the sale to Shell of specified levels of biomethane produced by DCE's landfill gas processing facility. There is, however, no guarantee that DCE will be able to produce or sell up to the maximum volumes called for under the agreement. DCE's ability to produce such volumes of biomethane depends on a number of factors beyond DCE's control, including, but not limited to, the availability and composition of the landfill gas that is collected, successful permitting, the operation of the landfill by the City of Dallas and the reliability of the processing facility's critical equipment. The DCE facility is subject to periods of reduced production or non-production due to upgrades, maintenance, repairs and other factors. For example, as part of an operational upgrade in March 2009, the facility was shut down for approximately one month. More recently, on June 12, 2009, the facility

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was taken offline for repairs that were completed on July 2, 2009. We anticipate that the facility will incur additional downtime for one to two weeks during the summer or fall of 2010 related to replacing the plant's gas driven compression with electric driven compression. Future operational upgrades or complications in the operations of the facility could require additional shutdowns, and accordingly, DCE's revenues may fluctuate from quarter to quarter.

Our quarterly results of operations have not been predictable in the past and have fluctuated significantly and may not be predictable and may fluctuate in the future.

        Our quarterly results of operations have historically experienced significant fluctuations. Our net losses were approximately $0.9 million, $3.6 million, $1.5 million, $2.9 million, $5.4 million, $3.2 million, $12.1 million, $23.7 million, $6.5 million, $6.4 million, $18.5 million, $1.9 million and $24.4 million for the three months ended March 31, 2007, June 30, 2007, September 30, 2007, December 31, 2007, March 31, 2008, June 30, 2008, September 30, 2008, December 31, 2008, March 31, 2009, June 30, 2009, September 30, 2009, December 31, 2009 and March 31, 2010, respectively. Our quarterly results may fluctuate significantly as a result of a variety of factors, many of which are beyond our control. In particular, if our stock price increases or decreases in future periods during which our Series I warrants are outstanding, we may be required to recognize corresponding losses or gains related to the valuation of the Series I warrants that could materially impact our results of operations. If our quarterly results of operations fall below the expectations of securities analysts or investors, the price of our common stock could decline substantially. Fluctuations in our quarterly results of operations may be due to a number of factors, including, but not limited to, our ability to increase sales to existing customers and attract new customers, the addition or loss of large customers, construction cost overruns, downtime at our facilities (including the recent shutdowns in March and June 2009 of DCE's landfill gas processing facility), the amount and timing of operating costs, unanticipated expenses, capital expenditures related to the maintenance and expansion of our business, operations and infrastructure, changes in the price of natural gas, changes in the prices of CNG and LNG relative to gasoline and diesel, changes in our pricing policies or those of our competitors, fluctuation in the value of our outstanding Series I warrants or natural gas futures contracts, the costs related to the acquisition of assets or businesses (for example, certain accounting guidance for business combinations requires that we adjust certain liabilities in connection with any business combination each reporting period, with a corresponding gain or loss reflected in the statement of operations, based on changes in the fair value of the obligation. We recorded a charge of $0.3 million for the three months ended March 31, 2010 related to additional consideration that we may need to pay to the shareholders of BAF in connection with our acquisition of BAF), regulatory changes, and geopolitical events such as war, threat of war or terrorist actions. Investors in our stock should not rely on the results of one quarter as an indication of future performance as our quarterly revenues and results of operations may vary significantly in the future. Therefore, period-to-period comparisons of our operating results may not be meaningful.

The future price of our common stock or the offering price of our common stock in future offerings could result in a reduction of the exercise price of our Series I warrants and result in dilution of our common stock.

        We issued Series I warrants to purchase up to 3,314,394 shares of our common stock in connection with our registered direct offering completed in November 2008. These warrants contain provisions that require an adjustment in the exercise price of the Series I warrants in the event that we price any offering of common stock at a price below the current exercise price, which is $12.68 per share after our follow-on equity offering we completed on July 1, 2009.

        In addition, on November 3, 2010, the exercise price per share of the Series I warrants could be reduced if the then current market price of our common stock is sufficiently less than the existing exercise price for the Series I warrants. In such an instance, the existing exercise price would reset to 120% of the then current market price of our common stock so long as such resulting price is less than

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the exercise price. If the Series I warrants are exercised, it would be dilutive to our stockholders by increasing the number of shares of our common stock outstanding, which would reduce our earnings per share.

Sales of outstanding shares of our stock into the market in the future could cause the market price of our stock to drop significantly, even if our business is doing well.

        If our stockholders sell, or indicate an intention to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline. As of March 31, 2010, 60,753,752 shares of our common stock were outstanding. The 11,500,000 shares sold in our initial public offering, the 4,419,192 shares of common stock and the 3,314,394 shares of common stock subject to outstanding warrants sold in our registered direct offering that closed on November 3, 2008, and the 9,430,000 shares of our common stock sold in our common stock offering that closed July 1, 2009 are freely tradable without restriction or further registration under federal securities laws unless purchased by our affiliates. Shares held by non-affiliates for more than six months may generally be sold without restriction, other than a current public information requirement, and may be sold freely without any restrictions after one year. All other outstanding shares of common stock may be sold under Rule 144 under the Securities Act, subject to applicable restrictions.

        In addition, as of March 31, 2010, there were 9,446,610 shares underlying outstanding options and 18,314,394 shares underlying outstanding warrants (including the 3,314,394 Series I warrant shares sold in our registered direct offering which closed on November 3, 2008). All shares subject to outstanding options and warrants are eligible for sale in the public market to the extent permitted by the provisions of various option and warrant agreements and Rule 144. If these additional shares are sold, or if it is perceived that they will be sold in the public market, the trading price of our stock could decline.

        Further, as of March 31, 2010, 16,539,720 shares of our stock held by our co-founder and board member T. Boone Pickens are subject to a pledge agreement with a bank. Should the bank be forced to sell the shares subject to the pledge, the trading price of our stock could also decline. In addition, a number of our directors and executive officers have entered into Rule 10b5-1 Sales Plans with a broker to sell shares of our common stock that they hold or that may be acquired upon the exercise of stock options. Sales under these plans will occur automatically without further action by the director or officer once the price and/or date parameters of the selling plan are achieved. As of March 31, 2010, 851,909 shares in the aggregate were subject to future sale by our named executive officers and directors under these selling plans. All sales of common stock under the plans will be reported through appropriate filings with the SEC.

A significant portion of our stock is beneficially owned by a single stockholder whose interests may differ from yours and who will be able to exert significant influence over our corporate decisions, including a change of control.

        As of March 31, 2010, Boone Pickens and affiliates (including Madeleine Pickens, his wife) owned in the aggregate 32% of our outstanding shares of common stock and beneficially owned in the aggregate approximately 46% of the outstanding shares of our common stock, inclusive of the 15,000,000 shares underlying a warrant held by Mr. Pickens. As a result, Mr. Pickens will be able to influence or control matters requiring approval by our stockholders, including the election of directors and the approval of mergers, acquisitions or other extraordinary transactions. Mr. Pickens may have interests that differ from yours and may vote in a way with which you disagree and which may be adverse to your interests. This concentration of ownership may have the effect of delaying, preventing or deterring a change of control of our company, could deprive our stockholders of an opportunity to receive a premium for their stock as part of a sale of our company, and might ultimately affect the market price of our stock. Conversely, this concentration may facilitate a change in control at a time when you and other investors may prefer not to sell.

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Item 2.—Unregistered Sales of Equity Securities and Use of Proceeds

        None.

Item 3.—Defaults upon Senior Securities

        None.

Item 4.—(Removed and Reserved)

Item 5.—Other Information

        None.

Item 6.—Exhibits

(a)

Exhibits

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SIGNATURE

        Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

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