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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 June 30, 2009

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 August 5, 2009, there were 59,692,712 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, 2008 and June 30, 2009 (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 and Six Months Ended

June 30, 2008 and 2009

(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 Six Months Ended June 30, 2008 and 2009

(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 185 natural gas fueling locations in Arizona, California, Colorado, District of Columbia, Georgia, Maryland, Massachusetts, Nevada, 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.

        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 and six months ended June 30, 2008 and 2009. All intercompany accounts and transactions have been eliminated in consolidation. The three and six month periods ended June 30, 2008 and 2009 are not necessarily indicative of the results to be expected for the year ending December 31, 2009 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, 2008 that are included in the Company's Annual Report on Form 10-K filed with the SEC on March 16, 2009.

        The Company has evaluated its subsequent events through August 10, 2009.

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 subject to certain post-closing adjustments. The Company has completed a preliminary allocation of the purchase consideration to tangible and intangible assets acquired and liabilities assumed based upon estimates of fair value. Such allocation includes $5.1 million to the identifiable intangible assets related to the fair value of the acquired operations and maintenance services contracts and associated customer relationships, which are being amortized over their expected lives. 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

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 2—Acquisitions (Continued)

the contracts and June 2009 for the remaining two contracts. The pro-forma effect of the acquisition is not material to the Company's results of operations for the six months ended June 30, 2009 and the year ended 2008.

Landfill Operation

        On August 15, 2008, the Company and Cambrian Energy McCommas Bluff LLC ("Cambrian") formed a joint venture to acquire all of the outstanding membership interests of Dallas Clean Energy, LLC ("DCE") which owns a facility that collects, processes and sells landfill gas at the McCommas Bluff landfill located in Dallas, Texas. This acquisition enables the Company to participate in the production of pipeline quality renewable biomethane which may be used as a vehicle fuel.

        The Company paid an aggregate of $19.6 million, including transaction costs, to acquire a 70% interest in DCE. Of the purchase price, $1.0 million was deposited into a third-party escrow as security for indemnification claims. The amount remaining in the escrow will be released to the sellers on August 15, 2009, except for amounts subject to pending indemnification claims, if any.

        Also as part of the transaction, the Company granted DCE's minority investor an exclusive, non-assignable option to purchase from the Company up to and including a 19% membership interest in DCE. The exercise price of the option is $368,000 for each 1%, up to $6,992,000 for the total 19%. The option may be exercised as a whole or in part (but only in 1% increments) during the ten-year period commencing on the date which the loan made by the Company to DCE has been repaid in full.

        The Company borrowed $18.0 million from PlainsCapital Bank ("PCB") to finance its 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 pursuant to a loan made by the Company to DCE and to pay certain costs and expenses related to the acquisition and the PCB loan. As of June 30, 2009, the Company had borrowed $7.7 million under the line of credit (see note 10).

        The Company accounted for the acquisition in accordance with SFAS No. 141, Business Combinations. The Company has completed a preliminary allocation of the purchase price. Such allocation and amounts may change as management finalizes its analyses. The assets acquired and liabilities assumed were recorded at their estimated fair values at the acquisition date. The following table summarizes the preliminary allocation of the aggregate purchase price to the fair value of the assets acquired and liabilities assumed, net of Cambrian's minority interest, in the DCE acquisition:

        Management preliminarily allocated approximately $21.8 million to the identifiable intangible asset related to the fair value of DCE's landfill lease with the City of Dallas that was acquired with the

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 2—Acquisitions (Continued)

acquisition. The fair value of the identifiable intangible asset will be amortized on a straight-line basis over the remaining life of the lease, approximately 16.5 years at the acquisition date.

        The results of DCE's operations have been included in the Company's consolidated financial statements since August 15, 2008. The pro-forma effect of the acquisition is not material to the Company's results of operations for the years ended December 31, 2007 and 2008.

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 SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended ("SFAS 133"). SFAS 133 requires the recognition of all derivatives as either assets or liabilities in the 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 SFAS 133. On and after July 1, 2008, the Company entered into futures contracts that did qualify for hedge accounting. The Company's futures contracts at June 30, 2009 are being accounted for as cash flow hedges under SFAS 133 and are being used to mitigate the Company's exposure to changes in the price of natural gas and not for speculative purposes. At June 30, 2009, 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 consolidated statements of operations or in accumulated other comprehensive income in the condensed consolidated balance sheets in accordance with the provisions of SFAS 133. The Company recorded unrealized losses of approximately $35,000 in accumulated other comprehensive income for the six month period ended June 30, 2009 related to its futures contracts. The liability for the Company's futures contracts of approximately $689,000 at June 30, 2009 is included in accrued liabilities and other long-term liabilities on the Company's condensed consolidated balance sheet at June 30, 2009. The Company's ineffectiveness related to its futures contracts during the six month period ended June 30, 2009 was insignificant. For the six month period ended June 30, 2009, the Company recognized losses of

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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)

approximately $1.1 million in cost of sales in the accompanying condensed consolidated statement of operations related to its futures contracts that did qualify for hedge accounting.

        The Company is required to make certain deposits on its futures contracts, should any exist. At June 30, 2009, the Company had $2.6 million of margin deposits related to its futures contracts covering approximately 35.2 million gallons of fuel, of which $668,000 related to contracts that expire in the next 12 months and were classified as current at June 30, 2009. The 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 June 30, 2009.

        The following table presents the notional amounts and weighted average fixed prices of the Company's natural gas futures contracts as of June 30, 2009:

Note 5—Fixed Price and Price Cap Sales Contracts

        The Company enters into contracts with various customers, primarily municipalities, to sell LNG or CNG at fixed prices, or through December 31, 2006, at prices subject to a price cap. The contracts generally range from two to five years. The most significant cost component of LNG and CNG is the price of natural gas.

        As part of determining the fixed price or price cap in the contracts, the Company works with its customers to determine their future usage over the contract term. However, the Company's fixed price and price cap customers do not agree to purchase a minimum amount of volume or guarantee their volume of purchases. There is not an explicit volume in the contract as the Company agrees to sell its customers volumes on an "as needed" basis, also known as a "requirements contract." The volume required under these contracts varies each month, and is not subject to any minimum commitments. For U.S. generally accepted accounting purposes, there is not a "notional amount," which is one of the required conditions for a transaction to be a derivative pursuant to the guidance in SFAS 133.

        The Company's sales agreements that fix the price or cap the price of LNG or CNG that it sells to its customers are, for accounting purposes, firm commitments, and U.S. generally accepted accounting principles do not require or allow the Company to record a loss until the delivery of the gas and corresponding sale of the product occurs. When the Company enters into these fixed price or price cap contracts with its customers, the price is set based on the prevailing index price of natural gas at that time. However, the index price of natural gas constantly changes, and a difference between the fixed price of the natural gas included in the customer's contract price and the corresponding index price of natural gas typically develops after the Company enters into the sales contract (with the price of natural gas having historically increased). From time to time, the Company has also entered into natural gas futures contracts to offset economically the adverse impact of rising natural gas prices (see

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 5—Fixed Price and Price Cap Sales Contracts (Continued)

note 4), and prior to December 31, 2006, if the Company believed the price of natural gas would decline in the future, periodically sold such contracts.

        Historically, from an accounting perspective, during periods of rising natural gas prices, the Company's futures contracts have generally been marked-to-market through the recognition of a derivative asset and a corresponding derivative gain in its statements of operations. However, because the Company's contracts to sell LNG or CNG to its customers at fixed prices or an index-based price that is subject to a fixed price cap are not derivatives for purposes of U.S. generally accepted accounting principles, a liability or a corresponding loss has not been recognized in the Company's statements of operations during this historical period of rising natural gas prices for the future commitments under these contracts. As a result, the Company's statements of operations do not reflect its firm commitments to deliver LNG or CNG at prices that are below, and in some cases, substantially below, the prevailing market price of natural gas (and therefore LNG or CNG).

Note 6—Other Receivables

        Other receivables at December 31, 2008 and June 30, 2009 consisted of the following:

Note 7—Land, Property and Equipment

        Land, property and equipment at December 31, 2008 and June 30, 2009 are summarized as follows:

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 8—Investments in Other Entities

        Through June 30, 2009, the Company invested approximately $6.4 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 July 16, 2009, the Company invested an additional $939,000 in VPG. The Company committed to fund up to $10.0 million in VPG from August 2008 through March 2010. $7.5 million is a firm commitment by the Company, and $2.5 million is contingent on VPG not being able to raise money on more-favorable terms than the funding from the original investor group. In addition, VPG may under certain circumstances make a capital call on investors which could require the Company to invest up to approximately $0.8 million in additional funds. 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.

        On August 27, 2008, a subsidiary of the Company converted outstanding commercial loans previously made to Bachman NGV, Inc. ("BAF"), a natural gas vehicle conversion company, into a secured convertible promissory note (the "Note") that is convertible into equity interests in BAF. The Note is convertible at the Company's option after August 27, 2009 and may be converted earlier upon an acquisition of BAF. As of June 30, 2009, the $3.8 million outstanding under the Note would convert into approximately 49% of the outstanding equity interests of BAF if fully converted. The Company may, at the Company's discretion, advance up to $2.2 million in additional funds to BAF under the Note. The Note bears interest at 5% per annum and is due August 30, 2010.

Note 9—Accrued Liabilities

        Accrued liabilities at December 31, 2008 and June 30, 2009 consisted of the following:

Note 10—Long-term Debt

        In conjunction with the Company's acquisition of its 70% interest in DCE (see note 2), 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 June 30, 2009, the Company had borrowed $7.7 million under the Facility B Loan. The Company may request funds up to an additional approximately $4.3 million

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 10—Long-term Debt (Continued)

under the Facility B Loan through August 14, 2009. Interest accrues daily on the Facility A and B Loans at the greater of the prime rate of interest for the United States plus 0.50% per annum or 5.50% per annum. The Company paid a facility fee of $300,000 in connection with the Credit Agreement. As of June 30, 2009, the unamortized balance of the facility fee was $247,500. Amortization of the facility fee is recorded as additional interest expense in the consolidated statements of operations.

        The Facility A Loan is due in level payments of principal and interest based on a 14 year amortization period. Payments of principal and interest are due on the 15th of each month until August 15, 2013, at which time the remaining amount of the unpaid principal and interest on the Facility A Loan is due and payable.

        Interest on the unpaid principal balance of the Facility B Loans became due and payable quarterly commencing on September 30, 2008. The principal amount of the Facility B Loans 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 Loans is due and payable.

        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 debt service ratio, as defined, of not less than 1.5 to 1 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 Facility A and B Loans. One of the events of default is the occurrence of a "material adverse change," which is a subjective acceleration clause. Based on the guidance in Emerging Issues Tax Force Issue No. 95-22 Balance Sheet Classification of Borrowings Outstanding under Revolving Credit Agreements That Include both a Subjective Acceleration Clause and a Lock-Box Arrangement (EITF No. 95-22), 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. To the extent natural gas prices fall, which a significant portion of the Company's revenues are derived from, 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

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 10—Long-term Debt (Continued)

Company is in compliance with the covenants as of June 30, 2009. 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 $45.0 million at June 30, 2009. The Company maintains $2.5 million in a payment reserve account at PCB. PCB may withdraw funds from the account to apply to the principal and interest payments due on Facility A and B Loans. Such amount is included as restricted cash in the Company's consolidated balance sheet at June 30, 2009.

        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 August 7, 2009 we have approximately $4.4 million in debt financing outstanding 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. 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 under the Facility A Loan and the Facility B Loan at June 30, 2009 are as follows:

Note 11—Correction of Immaterial Error

        Subsequent to the year ended December 31, 2008, the Company identified an error in the number of gallons it used to claim its Volumetric Excise Tax Credit ("VETC") refund. Due to this error, the Company's revenues were understated in 2007 and overstated in 2008.

        The Company assessed the materiality of this error for each quarterly and annual period in accordance with Staff Accounting Bulletin No. 99, Materiality, and determined that the error was immaterial to previously reported amounts contained in its periodic reports. Accordingly, the Company has revised its consolidated balance sheet as of December 31, 2008 and it intends to revise its

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 11—Correction of Immaterial Error (Continued)

consolidated financial statements for certain quarterly and annual periods through subsequent periodic filings. For quarters prior to June 30, 2008, the Company's financial statements have not been revised as the net amount of the error is insignificant. The effect of recording this immaterial correction in the statements of operations for the year ended December 31, 2008, the balance sheet as of December 31, 2008, and for the fiscal 2008 quarterly periods to be reported in subsequent periodic filings are as follows:

Note 12—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 June 30, 2008 and 2009, respectively, as the inclusion of the securities would be anti-dilutive to the calculation. The amounts outstanding as of June 30, 2008 and 2009 for these instruments are as follows:

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 13—Comprehensive Income (Loss)

        The following table presents the Company's comprehensive loss for the six months ended June 30, 2008 and 2009:

Note 14—Stock-Based Compensation

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

Stock Options

        The following table summarizes the Company's stock option activity during the six months ended June 30, 2009:

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 14—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 2009:

        Based on these assumptions, the weighted average grant date fair value of options granted during the six months ended June 30, 2009 was $4.16.

Note 15—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.

Note 16—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 which 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 has been and may become party to various legal actions that arise in the ordinary course of its business. During the course of its operations, the Company has been, currently is and may become 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.

Note 17—Income Taxes

        FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109" (FIN 48), requires that the Company 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

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 17—Income Taxes (Continued)

authority upon examination, based on the technical merits of the position. FIN 48 requires the Company to accrue interest based on the difference between the tax position recognized in the financial statements and the amount claimed on the return. The net interest incurred was immaterial for the six months ended June 30, 2008 and 2009. FIN 48 further requires that penalties be accrued 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 June 30, 2009 are unchanged from December 31, 2008. It is anticipated that the Company's liability for uncertain tax positions will be reduced by as much as $319,000 during the year as a result of the settlement of tax positions with various tax authorities.

        The Company is subject to taxation in the United States and various states and foreign jurisdictions. The Company's tax years for 2003 through 2007 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 2004. The Company is currently under audit by the Internal Revenue Service for tax years 2005 through 2007.

Note 18—Fair Value Measurements

        On January 1, 2008, the Company adopted the applicable provisions of SFAS No. 157, Fair Value Measurements ("SFAS 157"), 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 FASB provided a one-year deferral of SFAS 157 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 SFAS 157 for non-financial assets and non-financial liabilities on January 1, 2009.

        During the six months ended June 30, 2009, the Company's financial instruments consisted of natural gas futures contracts, debt instruments, and its Series I warrants. 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 estimates regarding risk-free interest rates, the volatility of its stock price, and its anticipated dividend yield. The Company's futures contracts are recorded in accrued liabilities and other long-term liabilities and the Series I warrants are recorded in other long-term liabilities in the accompanying condensed consolidated balance sheet at June 30, 2009. The fair market value of the Company's debt instruments approximated their carrying values at June 30, 2009.

        The following table reflects the fair value as defined by SFAS 157, of the Company's natural gas futures contracts and the Series I warrants at June 30, 2009:

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 19—Recently Adopted Accounting Changes and Recently Issued Accounting Standards

        In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141(R), Business Combinations ("SFAS 141(R)"). SFAS 141(R) provides new accounting guidance and disclosure requirements for business combinations. SFAS 141(R) is effective for business combinations which occur beginning in 2009. The adoption of SFAS 141(R) did not have a material impact on the Company's financial statements.

        In December 2007, the FASB issued Statement of Financial Accounting Standard No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51 ("SFAS 160"). SFAS 160 requires presentation of non-controlling interests in consolidated subsidiaries separately within equity in the consolidated statements of financial position as well as the separate presentation within the consolidated statements of operations and comprehensive income (loss) attributable to the parent and noncontrolling interest. Accounting for changes in a parent's ownership interest, will generally be at fair value and if the parent retains control or significant influence of the subsidiary, any adjustments will be made through equity, while transactions where control changes occur will be accounted for through earnings. SFAS 160 was effective for the Company on January 1, 2009. As a result of adopting SFAS 160, the Company reclassified the minority interest of DCE to the stockholders' equity section of the consolidated balance sheet. References to minority interest in previous financial statements are now reflected as noncontrolling interest. The adoption of this statement did not have a material impact on the Company's consolidated financial position or results of operations.

        In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, "Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133" ("SFAS 161"). SFAS 161 amends and expands the disclosure requirements of FASB Statement No. 133 (SFAS 133), requiring enhanced disclosures about the Company's derivative and hedging activities. The Company is required to provide enhanced disclosures about (a) how and why it uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect the Company's financial position, results of operations, and cash flows. The Company adopted this statement as of January 1, 2009 and the adoption did not have a material impact on its consolidated financial statements.

        In April 2008, the FASB issued FASB Staff Position No. FAS 142-3, Determination of the Useful Life of Intangible Assets ("FSP FAS 142-3"). FSP FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, Goodwill and Other Intangible Assets. More specifically, FSP FAS 142-3 removes the requirement under paragraph 11 of SFAS 142 to consider whether an intangible asset can be renewed without substantial cost or material modifications to the existing terms and conditions and instead, requires an entity to consider its own historical experience in renewing similar arrangements. FSP FAS 142-3 also requires expanded disclosure related to the determination of intangible asset useful lives. FSP FAS 142-3 was effective for the Company on January 1, 2009. Adoption of this statement did not have a material impact on the Company's consolidated financial statements.

        In June 2008, the Emerging Issues Task Force (the "EITF") reached a consensus in EITF No. 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity's Own Stock

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 19—Recently Adopted Accounting Changes and Recently Issued Accounting Standards (Continued)

(EITF No. 07-5). The EITF 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. As a result of this guidance, effective January 1, 2009, the Company accounts for the Series I warrants as a derivative under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. As a result of adopting EITF No. 07-5, 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 adoption, January 1, 2009. During the second quarter of 2009, the Company recorded a charge of $2.4 million related to valuing the Series I warrants.

        In May 2009, the FASB issued Statement of Financial Accounting Standards No. 165, Subsequent Events, ("SFAS 165") which establishes general standards of accounting for and disclosures of events that occur after the balance sheet date, but before the financial statements are issued or are available to be issued. SFAS 165 requires the disclosure of the date through which an entity has evaluated subsequent events, and is effective for interim and annual reporting periods ending after June 15, 2009. The Company adopted the new disclosure requirements on April 1, 2009 and its adoption did not have a material impact on the Company's consolidated financial statements.

        On June 30, 2009, the FASB issued FSP SFAS 107-1, Interim Disclosures about Fair Value of Financial Instruments. FSP 107-1, which amends SFAS No. 107, Disclosures about Fair Value of Financial Instruments, requires publicly-traded companies, as defined in APB Opinion No. 28, Interim Financial Reporting, to provide disclosures on the fair value of financial instruments in interim financial statements. The Company adopted the new disclosure requirements on April 1, 2009 and its adoption did not have a material impact on the Company's consolidated financial statements.

        In April 2009, the FASB issued FSP SFAS 157-4, "Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly," which provides additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for the asset or liability have significantly decreased. This FSP re-emphasizes that regardless of market conditions the fair value measurement is an exit price concept as defined in SFAS No. 157. This FSP clarifies and includes additional factors to consider in determining whether there has been a significant decrease in market activity for an asset or liability and provides additional clarification on estimating fair value when the market activity for an asset or liability has declined significantly. The scope of this FSP does not include assets and liabilities measured under Level 1 inputs. The Company adopted FSP SFAS 157-4 on April 1, 2009 and its adoption did not have a material impact on the Company's consolidated financial statements.

        On July 1, 2009, the FASB's Accounting Standards Codification, ("Codification") was released. The Codification will become the source of authoritative U.S. generally accepted accounting principles ("GAAP") recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 19—Recently Adopted Accounting Changes and Recently Issued Accounting Standards (Continued)

releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of this Statement, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in the Codification will become nonauthoritative. This Statement is effective for the Company's consolidated financial statements issued for interim and annual periods ending after September 15, 2009. The Company does not expect transition to the Codification will have a material impact on the Company's consolidated financial statements.

Note 20—Subsequent Events

        On July 1, 2009, the Company closed a follow-on public offering of 9,430,000 shares of common stock at a price of $8.30 per share. The aggregate amount of common shares sold reflects the exercise in full by the underwriters of their option to purchase 1,230,000 additional shares of the Company's common stock to cover over-allotments. The Company received aggregate net proceeds of approximately $73.2 million, after deducting underwriting discounts and commissions and estimated offering expenses payable by the Company.

        As a result of the follow-on public offering, the exercise price of the Company's Series I Warrants issued on October 28, 2008 was adjusted to $12.68 per share from $13.50 per share per the terms of the Series I warrant agreements.

Note 21—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 six month periods ended June 30, 2008 and 2009 were approximately $9.1 million and $8.1 million, respectively.

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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, 2008 contained in our 2008 Annual Report, 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 2008 Annual Report. In preparing this MD&A, we presume that readers have access to and have read the MD&A in our 2008 Annual Report 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.

        We provide natural gas solutions for vehicle fleets primarily in the United States and Canada. Our primary business activity is selling CNG and 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.

Overview

        This overview discusses matters on which our management primarily focuses in evaluating our financial condition and operating performance.

        Sources of revenue.    We generate the 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 and sales of pipeline quality biomethane produced by our DCE joint venture.

        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 O&M services but do not directly

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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 revenue; 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, 2006, 2007 and 2008 and for the three and six months ended June 30, 2008 and 2009:

 

        Key trends in 2006, 2007, and 2008 and the first six months of 2009.    Vehicle fleet demand for natural gas fuels increased during the three year and six-month period ended June 30, 2009. We believe this growth in demand was attributable primarily to the rising prices of gasoline and diesel relative to CNG and LNG during this period and increasingly stringent environmental regulations affecting vehicle fleets. We capitalized on this growing demand by securing new fleet customers in a variety of markets, including public transit, refuse hauling, airports, taxis and regional trucking.

        The number of fueling stations we served grew from 147 at December 31, 2004 to 185 at June 30, 2009 (a 25.9% increase). The amount of CNG and LNG gasoline gallon equivalents we delivered from 2006 to 2008 increased by 7.5%. The increase in gasoline gallon equivalents delivered, together with higher prices we charged our customers due to higher natural gas prices, contributed to increased revenues from 2006 through the end of 2008. During the first six months of 2009, our revenues declined as compared to the first six months of 2008 primarily due to lower natural gas prices. Our cost of sales also increased from 2006 through the end of 2008, which was attributable primarily to the increased costs related to delivering more CNG and LNG to our customers and the increased price of natural gas. Our cost of sales decreased during the first six months of 2009 as compared to the first six months of 2008 primarily due to lower natural gas prices.

        Recent developments.    On July 1, 2009, we closed a follow-on public offering of 9,430,000 shares of common stock at a price of $8.30 per share. The aggregate amount of common shares sold reflects the exercise in full by the underwriters of their option to purchase 1,230,000 additional shares of our common stock to cover over-allotments. We received aggregate net proceeds of approximately $73.2 million, after deducting underwriting discounts and commissions and estimated offering expenses.

        Anticipated future trends.    Despite the recent volatility and decline in energy prices, 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 producing rates. The study indicated a mean level of reserves

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equal to 88 years of supply at 2007 production levels. Indications were that shale gas production growth from only the major six shale plays, 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 current surplus of gas supply 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 making available gas supply to meet all existing markets and to meet new market requirements. Analysts believe that there is a significant worldwide supply of natural gas relative to crude oil as well. According to the 2008 BP Statistical Review of World Energy, on a global basis, the ratio of proven natural gas reserves to 2007 natural gas production was 45% greater than the ratio of proven crude oil reserves to 2007 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. 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 as well as the logistics of delivering more CNG and LNG to our customers. 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.

        The disruption in the capital markets that began during 2008 and has continued into 2009 has made it more difficult for new customers to finance or invest in natural gas vehicle acquisitions or natural gas fueling stations. Continuing economic contraction and reduced economic activity may reduce our opportunities to attract new fleet customers. Many governmental entities, which during 2006 through 2008 represented approximately two-thirds of our revenues, 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 transportation and services, which would negatively affect our business.

        Sources of liquidity and anticipated capital expenditures.    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. Historically, our principal sources of liquidity have been cash provided by operations, capital contributions from our stockholders, our cash and cash equivalents and, during the third and fourth quarters of fiscal 2006, a revolving line of credit with Boone Pickens, a director and our largest stockholder. The line of credit was used to fund margin requirements on certain derivative contracts and was terminated in December 2006. In connection with our acquisition of 70% of the membership interests in DCE, we entered into a credit agreement on August 15, 2008 with PCB. We borrowed $18.0 million to finance the acquisition and entered into a $12.0 million line of credit from PCB to provide capital to DCE, primarily for capital expenditures, and to pay certain costs and expenses of the acquisition and the loans. As of August 7, 2009, approximately $4.3 million is available under the line of credit from PCB to provide further capital to DCE, however, we may only draw down on the line of credit through August 14, 2009. On September 24, 2008, we sold 319,488 shares of our common stock at a purchase 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 shares of common stock and warrants exercisable for common stock to third-party investors and

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received net proceeds of approximately $32.5 million. On July 1, 2009, we sold 9,430,000 shares of common stock to third-party investors and received net proceeds of $73.2 million.

        Our current business plan calls for approximately $14.9 million in additional capital expenditures from July 1, 2009 through the end of 2009, primarily related to construction of new fueling stations. In addition, we anticipate that during the remainder of 2009 we will provide approximately $0.3 million for financing natural gas vehicle purchases by our customers and up to $2.5 million in funding that we may be required to provide to the Vehicle Production Group, LLC, a company that is developing CNG paratransit vehicles and taxis. We anticipate that we will fund any capital expenditures of DCE during 2009 through our available cash reserves or our line of credit from PCB, if we fund such capital expenditures prior to August 14, 2009. We may also elect to invest additional amounts that are not budgeted for in our 2009 business plan in expansion of our California LNG plant, station construction for new or existing customers that are not currently under contract or for acquisitions or investments in companies or assets in the natural gas and biomethane fueling infrastructure, services and production industries. We intend to fund our principal liquidity requirements, other than our loan to DCE, through cash and cash equivalents and cash provided by operations. For more information, see "Liquidity and Capital Resources" below.

        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 SFAS No. 133, and in 2008, some of our contracts qualified for hedge accounting under SFAS No. 133 and some did not. In 2009, all of our futures contracts did qualify for hedge accounting under SFAS 133. 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.

        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 six months ended June 30, 2009, CNG and biomethane (together) represented 73% and LNG represented 27% 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. 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. In 2006, we began providing vehicle finance services to our customers.

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

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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 sell a small amount of CNG under fixed-price contracts and also provide price caps to certain customers on their index-plus pricing arrangement. 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 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. In April 2008, we opened our first CNG station in Lima, Peru through our joint venture Clean Energy del Peru.

LNG Sales

        We sell substantially all of our LNG to fleet customers, who typically own and operate their fueling stations. We also sell a small volume of LNG to customers for non-vehicle use. We procure LNG from third-party producers and also produce LNG at our liquefaction plants in Texas and California. For LNG that we purchase from third-parties, we typically enter into "take or pay" contracts that require us to purchase 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, including a one-year renewal period beginning April 1, 2010 that one of our customers is entitled to should they choose to exercise such renewal. This renewal period, if exercised, would obligate us to sell the customer approximately 2.1 million LNG gallons subject to a price cap of $7.50 per MMbtu on the SoCal Border Index. 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 may receive a VETC of $0.50 per gasoline gallon equivalent of CNG and $0.50 per liquid gallon of LNG that we sell as vehicle fuel. Based on the service relationship we have with our customers, either we or our customers are able to claim the credit. We record 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 SFAS No. 109. 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. We expect the tax credit will continue to factor into the price we charge our customers for CNG and LNG in the future. The legislation that created this tax credit also increased the federal excise taxes on sales of CNG from $0.061 to $0.183 per gasoline gallon equivalent and on sales of LNG from $0.119 to $0.243 per LNG gallon.

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."

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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 on average 60% and on occasion up to 100% of the purchase price of their natural gas vehicles. We may also lease vehicles in the future. Where 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 June 30, 2009, 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 and for the six months ended June 30, 2009, DCE generated approximately $1.8 million and $2.5 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. The gas sale agreement calls for the sale of up to the following quantity of biomethane by DCE to Shell daily:

April 2009 through September 2010: 4500 MMBtus per day
October 2010 through December 2010: 5200 MMBtus per day
Calendar year 2011: 5300 MMBtus per day
Calendar year 2012: 5400 MMBtus per day
Calendar year 2013: 5300 MMBtus per day
Calendar year 2014: 5300 MMBtus per day
Calendar year 2015-2018: 5000 MMBtus per day
Calendar year 2019 to March 2024: 6000 MMBtus per day

        DCE's obligation and ability to sell greater than 4500 MMBtus per day is contingent on the successful permitting and commencement of commercial operation of an expansion to the existing gas processing facility to at least 15 million standard cubic feet per day inlet capacity of raw landfill gas. 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

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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 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 current prevailing prices for natural gas.

        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 and pipeline quality biomethane production. 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 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).

Volatility of Earnings and Cash Flows Related to Natural Gas Futures Contracts

        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 not historically qualified for hedge accounting under SFAS 133. 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 $0.3 million, $65.0 million, $13.7 million, $6.0 million and $0.3 million for the three months ended March 31, 2006, September 30, 2006, December 31, 2006, September 30, 2008 and December 31, 2008, respectively. We had no derivative gains or losses for the three months ended June 30, 2006, March 31, 2007, June 30, 2007, September 30, 2007, December 31, 2007, March 31, 2008, March 31, 2009 and June 30, 2009 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 SFAS No. 133, 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

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payments could significantly impact our cash balances. At June 30, 2009, we had $2.6 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.

Volatility of Earnings Related to Series I Warrants

        Beginning January 1, 2009, under EITF No. 07-5, we are required to record the change in the fair market value of our Series I warrants in our financial statements. We recognized an expense of $0.2 million and $2.4 million related to recording the fair market value changes of our Series I warrants in the quarters ended March 31, 2009 and June 30, 2009, respectively.

Debt Compliance

        Our credit agreement with 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 debt service ratio, as defined, of not less than 1.5 to 1 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. However, if we default on the Credit Agreement, all of the obligations under the Credit Agreement will become due and payable and all funds received in our lock-box held by PCB will be applied to the balance due 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 guidance in Emerging Issues Tax Force Issue No. 95-22 Balance Sheet Classification of Borrowings Outstanding under Revolving Credit Agreements That Include both a Subjective Acceleration Clause and a Lock-Box Arrangement (EITF No. 95-22), 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 and $2.5 million we have deposited with PCB in a payment reserve account will be applied to the balance due on the Credit Agreement. We were in compliance with the covenants as of June 30, 2009.

        One of our bank covenants is a requirement to maintain accounts receivable balances from certain subsidiaries above $8.0 million at each quarter-end during the term. To the extent natural gas prices continue to fall, which a significant portion of our revenues are derived from, 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 debt service ratio, as defined, of not less than 1.5 to 1. 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.

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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 2008 Annual Report, which discussion is incorporated herein by reference.

        In an effort to mitigate the volatility of our earnings related to our futures contracts and to reduce our risk related to fixed-price sales contracts, our board of directors revisited our risk management policies and procedures and adopted a revised natural gas hedging policy in February 2007, which was amended effective May 29, 2008 and restricts our ability to purchase natural gas futures contracts and offer fixed-price sales contracts to our customers. Unless otherwise agreed in advance by the board of directors and the derivative committee, we will conduct our futures activities and enter into fixed-price sales contracts only in accordance with the natural gas hedging policy, a complete copy of which was filed as Exhibit 99.1 to our Form 8-K filed with the SEC on June 20, 2008 and is incorporated by reference herein. Pursuant to the policy, we only purchase futures contracts to hedge our exposure to variability in expected future cash flows related to a particular fixed price contract or bid. Subject to the conditions set forth in the policy, we purchase futures contracts in quantities reasonably expected to hedge effectively our exposure to cash flow variability related to such fixed-price sales contracts entered into after the date of the policy. The summary of the policy described above does not purport to be complete and is qualified in its entirety by reference to the copy of the policy previously filed.

        Due to the restrictions of our revised hedging policy, we expect to offer significantly fewer fixed-price sales contracts to our customers. If we do offer a fixed-price sales contract, we anticipate including a price component that would cover our increased costs as well as a return on our estimated cash requirements over the duration of the underlying futures contract. The amount of this price component will vary based on the anticipated volume to be covered under the fixed-price sales contract.

Critical Accounting Policies

        For the first six months of 2009, 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 2008 Annual Report.

Recently Issued Accounting Pronouncements

        For a description of recently issued accounting pronouncements, see note 19 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 June 30, 2009 Compared to Three Months Ended June 30, 2008

        Revenue.    Revenue decreased by $5.9 million to $27.9 million in the three months ended June 30, 2009, from $33.8 million in the three months ended June 30, 2008. This decrease was primarily due to a decrease in our average price per gallon we charged between periods. Our effective price per gallon was $1.00 in the three months ended June 30, 2009, which represents a $0.57 per gallon decrease from $1.57 in the three months ended June 30, 2008. The decrease was primarily due to the decreased price of natural gas in the second quarter of 2009, upon which a significant amount of our revenues are based. Revenue also decreased between periods as we recorded $4.0 million of revenue related to fuel tax credits in the second quarter of 2009, compared to $4.4 million in the second quarter of 2008, and we experienced a $0.3 million decrease in station construction revenues between periods. These decreases were offset by the increase in the number of gallons delivered between periods from 18.5 million gasoline gallon equivalents to 23.7 million gasoline gallon equivalents. The increase in volume was primarily from an increase in biomethane sales (our 70% share of the biomethane sales of DCE) and CNG sales of 1.5 million and 4.5 million gallons, respectively. We believe that the biomethane sales increase was primarily attributable to our investment in new wells and the capital upgrades to the processing plant that were completed in the first quarter of 2009. The acquisition of

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four compressed natural gas operations and maintenance services contracts in May, three new refuse customers (Brookhaven Carters, CalMet Services and CleanScapes) and one new transit customer (Regional Transit Authority of Ohio) together accounted for 3.7 million gallons of the CNG volume increase. The volume growth from our joint venture in Peru and from existing refuse and airport customers contributed to the remaining CNG volume increase. Offsetting these increases is a 0.8 million gallon decrease in LNG volumes, which was primarily due to the loss of a portion of the City of Phoenix LNG supply contract for the period July 1, 2008 through June 30, 2009.

        Cost of sales.    Cost of sales decreased by $12.4 million to $16.2 million in the three months ended June 30, 2009, from $28.6 million in the three months ended June 30, 2008. Our cost of sales primarily decreased between periods as a result of our effective cost per gallon declining by $0.85 per gallon to $0.68 in the three months ended June 30, 2009, primarily due to the decreased price of natural gas in the second quarter of 2009. Offsetting this decrease was a $3.5 million increase in costs related to delivering more volume between periods. We also experienced a $0.2 million decrease in station construction costs between periods.

        Derivative (gain) loss.    Derivative (gains) losses decreased by $7.9 million to a $2.2 million loss in the three months ended June 30, 2009, from a $5.7 million gain in the three months ended June 30, 2008. The 2009 amount represents the adoption of EITF No. 07-5 that requires us to mark-to-market our Series I warrants (see note 19 to our condensed consolidated financial statements contained elsewhere herein). The 2008 amount represents a gain we recognized in the three months ended June 30, 2008 on futures contracts we purchased in April 2008 in conjunction with a fixed-price bid on a LNG supply contract we submitted. Our futures contracts we owned during the three months ended June 30, 2009 qualified for hedge accounting under SFAS 133.

        Selling, general and administrative.    Selling, general and administrative expenses decreased by $0.5 million to $11.6 million in the three months ended June 30, 2009, from $12.1 million in the three months ended June 30, 2008. Our marketing expenses decreased $2.4 million between periods as we did not incur certain advertising costs related to the Ports of Los Angeles and Long Beach and to support the Clean Alternative Fuels Act in California in the second quarter of 2009 as we did in the second quarter of 2008. This decrease was offset by a $0.9 million increase in stock option expense between periods, primarily due to options granted to our employees in December 2008 and January 2009, and an increase of $0.8 million in bonus expense between periods due to higher anticipated payouts in 2009.

        Depreciation and amortization.    Depreciation and amortization increased by $1.9 million to $4.1 million in the three months ended June 30, 2009, from $2.2 million in the three months ended June 30, 2008. This increase was primarily related to additional depreciation expense in the three months ended June 30, 2009 related to increased property and equipment balances between periods, primarily related to our expanded station network and our California LNG plant. Our June 30, 2009 amortization amount also includes amortization of the City of Dallas Landfill lease that we acquired in connection with our acquisition of DCE on August 15, 2008 and amortization of the customer contract intangible assets we obtained in connection with our acquisition of the operation and maintenance contracts we acquired during the period.

        Interest income (expense), net.    Interest income (expense), net, decreased by $325,000 to $60,000 of expense for the three months ended June 30, 2009. This decrease was primarily the result of a decrease in interest income in the three months ended June 30, 2009 due to lower average cash balances on hand during the three months ended June 30, 2009. We also incurred interest expense of $0.2 million in the second quarter of 2009, net of amounts capitalized, related to the debt we incurred to acquire our interest in DCE in August 2008 that we did not incur in the second quarter of 2008.

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        Other income (expense), net.    Other income (expense), net, was $146,000 of expense in the three months ended June 30, 2009, as compared to $2,000 of income in the three months ended June 30, 2008. The decrease was primarily related to the write-off of certain non-recoverable station costs in the three months ended June 30, 2009 that did not occur in the three months ended June 30, 2008.

        Income (loss) from equity method investments.    There was no significant change in income (loss) from equity method investments between the three months ended June 30, 2009 and the three months ended June 30, 2008.

        Loss of noncontrolling interest in net income.    During the three months ended June 30, 2009, we recorded $0.1 million of loss for the noncontrolling interest in the net loss of DCE. The noncontrolling interest represents the 30% interest of our joint venture partner. The results of DCE's operations have been included in the consolidated financial statements since August 15, 2008, the date of acquisition.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

        Revenue.    Revenue decreased by $5.7 million to $58.1 million in the six months ended June 30, 2009, from $63.8 million in the six months ended June 30, 2008. This decrease was primarily the result of a decrease in our average price per gallon between periods. Our effective price per gallon was $1.06 in the six months ended June 30, 2009, which represents a $0.44 per gallon decrease from $1.50 in the six months ended June 30, 2008. The decrease was primarily due to the decreased price of natural gas in the first six months of 2009, upon which a significant amount of our revenues are based. Revenue also decreased between periods as we recorded $8.1 million of revenue related to fuel tax credits in the first six months of 2009, compared to $9.1 million in the first six months of 2008. These decreases were offset by the increase in the number of gallons delivered between periods from 36.1 million gasoline gallon equivalents to 42.0 million gasoline gallon equivalents. A significant portion of the volume increase was due to an increase in biomethane sales (our 70% share of the biomethane sales of DCE) and CNG sales of 2.4 million and 5.0 million gallons, respectively. A significant portion of the CNG volume increase was the result of 3.2 million gallons we delivered in the second quarter of 2009 related to the acquisition of four compressed natural gas operations and maintenance services contracts in May and June, 2009. We also had volume increases of 0.5 million gallons for three new refuse customers (Brookhaven Carters, CalMet Services and CleanScapes), 0.5 million gallons related to our interest in our joint venture in Peru and 0.2 million gallons from a new transit customers (Regional Transit Authority of Ohio). The volume growth from our existing refuse and airport customers contributed to the remaining CNG volume increase. Offsetting these increases is a 1.5 million gallons decrease in LNG volumes, which was primarily due to the loss of a portion of the City of Phoenix LNG supply contract for the period July 1, 2008 through June 30, 2009. We also experienced a $4.8 million increase in station construction revenues between periods.

        Cost of sales.    Cost of sales decreased by $13.2 million to $37.8 million in the six months ended June 30, 2009, from $51.0 million in the six months ended June 30, 2008. Our cost of sales primarily decreased between periods as a result of our effective cost per gallon declining by $0.62 per gallon to $0.79 in the six months ended June 30, 2009, primarily due to the decreased price of natural gas in the first six months of 2009. Offsetting the decrease was the increase in station construction costs of $4.4 million between periods and a $4.7 million increase in costs related to delivering more volume between periods.

        Derivative (gains) losses.    Derivative (gains) losses decreased by $8.1 million to a $2.4 million loss in the six months ended June 30, 2009, from a $5.7 million gain in the six months ended June 30, 2008. The 2009 amount represents the adoption of EITF No. 07-5 that requires us to mark-to-market our Series I warrants (see note 19 to our condensed consolidated financial statements contained elsewhere herein). The 2008 amount represents a gain we recognized in the six months ended June 30, 2008 on futures contracts we purchased in April 2008 in conjunction with a fixed-price bid on a LNG supply

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contract we submitted. Our futures contracts we owned during the six months ended June 30, 2009 qualified for hedge accounting under SFAS 133.

        Selling, general and administrative.    Selling, general and administrative expenses decreased by $0.5 million to $23.2 million in the six months ended June 30, 2009, from $23.7 million in the six months ended June 30, 2008. A significant portion of this decrease related to a $3.8 million decrease in our marketing expenses between periods due to certain advertising we conducted in 2008 related to the Ports of Los Angeles and Long Beach and costs we incurred in 2008 to support the Clean Alternative Fuels Act in California that did not occur in 2009. Offsetting this decrease was an increase in stock option expense between periods of $1.9 million, primarily due to options granted to our employees in December 2008 and January 2009, and an increase of $1.3 million in salaries and benefits between periods. The salaries and benefits increase was primarily due to an increase in our bonus expense between periods due to higher anticipated payouts in 2009 and a headcount increase from 133 at June 30, 2008 to 155 at June 30, 2009.

        Depreciation and amortization.    Depreciation and amortization increased by $3.5 million to $7.7 million in the six months ended June 30, 2009, from $4.2 million in the six months ended June 30, 2008. This increase was due to additional depreciation expense in the six months ended June 30, 2008 related to increased property and equipment balances between periods, primarily related to our expanded station network and our California LNG plant. Our June 30, 2009 amortization amount also includes amortization of the identifiable intangible asset recorded in connection with the acquisition of our 70% interest in DCE in August 2008, and amortization of the customer contract intangible assets we obtained in connection with our acquisition of four operations and maintenance contracts we acquired during the period.

        Interest income, net.    Interest income, net, decreased by $1.2 million from $1.1 million of income for the six months ended June 30, 2008, to $92,000 of expense for the six months ended June 30, 2009. This decrease was primarily the result of a decrease in interest income in the six months ended June 30, 2009 due to lower average cash balances on hand between periods. We also incurred interest expense of $0.4 million in the second quarter of 2009, net of amounts capitalized, related to the debt we incurred to acquire our interest in DCE in August 2008 that we did not incur in the first six months of 2008.

        Other income (expense), net.    Other income (expense), net, was $187,000 of expense in the six months ended June 30, 2009, as compared to $40,000 of income in the six months ended June 30, 2008. The decrease was primarily related to the write-off of certain non-recoverable station costs in the six months ended June 30, 2009 that did not occur in the six months ended June 30, 2008, and the sale of certain assets in the six months ended June 30, 2008 that did not occur in the six months ended June 30, 2009.

        Income (loss) from equity method investments.    Income (loss) from equity method investments increased $192,000 to $52,000 of income for the six months ended June 30, 2009 related to our share of our joint venture in Peru.

        Loss of noncontrolling interest in net income.    During the six months ended June 30, 2009, we recorded a $0.5 million loss for the noncontrolling interest in the net loss of DCE. The noncontrolling interest represents the 30% interest of our joint venture partner. The results of DCE's operations have been included in the consolidated financial statements since August 15, 2008, the date of acquisition.

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

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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 have borrowed $18.0 million under a term loan and an additional $7.7 million (as of June 30, 2009) under a line of credit (see note 10 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.

        In addition to funding operations, our principal uses of cash have been, and are expected to be, the construction of new fueling stations, the construction of a new LNG liquefaction plant in California, the purchase of new LNG tanker trailers, 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 six months of 2009 primarily through cash on hand and cash provided by operations.

        At June 30, 2009, we had total cash and cash equivalents of $19.8 million, compared to $36.3 million at December 31, 2008.

        Cash provided by operating activities was $5.6 million for the six months ended June 30, 2009, compared to cash used in operating activities of $12.9 million for the six months ended June 30, 2008. The increase in operating cash flow resulted primarily from improved operating results between periods, and increased collections of accounts and other receivables between periods of $3.7 million and a net return of $5.2 million in LNG truck deposits between periods. The remaining changes primarily resulted from changes in working capital balances, which were mostly due to timing differences related to the various cash flows between periods.

        Cash used in investing activities was $24.5 million for the six months ended June 30, 2009, compared to $32.6 million for the six months ended June 30, 2008. Our purchases of property and equipment were $18.2 million during the first six months of 2009, compared to $36.7 million for the same period in 2008. We also acquired four compressed natural gas operations and maintenance services contracts for $5.6 million during the second quarter of 2009. We made additional investments during the first six months of 2009 totaling $2.0 million in the Vehicle Production Group, LLC, a company developing a CNG taxi and a paratransit vehicle. In June 2009, we sold certain customer vehicle loans to a bank for net proceeds of $1.3 million. In the first six months of 2008, we purchased $43.4 million of short-term investments with our initial public offering proceeds from May 2007, of which $47.5 million matured or were sold during the period. We did not have any short-term investments during the first six months of 2009.

        Cash provided by financing activities for the six months ended June 30, 2009 was $2.4 million, compared to $103,000 for the six months ended June 30, 2008. In February 2009, we borrowed an additional $3.1 million from PCB to fund capital expenditures for an upgrade to DCE's biomethane plant. This increase in cash was offset by repayments on our capital lease and long-term debt instruments of $0.7 million.

        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,

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our capital expenditure requirements (which consist primarily of station construction, LNG plant construction costs, and the purchase of LNG tanker trailers and equipment) and any merger or acquisition activity.

Capital Expenditures

        Our current business plan calls for approximately $14.9 million in additional capital expenditures from July 1, 2009 through the end of 2009, primarily related to construction of new fueling stations. In addition, we anticipate that during the remainder of 2009 we will provide approximately $0.3 million for financing natural gas vehicle purchases by our customers and up to $2.5 million in financing that we may be required to provide to the Vehicle Production Group LLC, a company that is developing CNG paratransit vehicles and taxis. Through August 7, 2009, we have $4.4 million in debt financing outstanding under our loan agreement with DCE and we anticipate that we will provide up to approximately $6.8 million in additional loan financing to DCE during the remainder of 2009 for additional capital expenditures and expenses. Financing provided to DCE is not included in our 2009 capital expenditure business plan. We anticipate that we will fund all additional financing we provide to DCE through available cash reserves or our $12.0 million Facility B loan with PCB, which has approximately $4.3 million in remaining available credit as of August 7, 2009 which may be accessed through August 14, 2009. We intend to fund our principal liquidity requirements over the next twelve months, other than our loan to DCE, through cash and cash equivalents and cash provided by operations. If we have significant unanticipated capital expenditures, investments, acquisitions or operating expenses, we may seek to raise capital to fund such capital expenditures, investments, acquisitions or expenses. Due to the continuing disruption in the capital markets, 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 and invest in strategic transactions or acquisitions and reduce our ability to invest in our business and generate increased revenues.

        Our credit agreement with PCB requires that we comply with certain covenants, as detailed in footnote 10 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 continue to fall, which would result in decreased revenues, or our volumes sold decline, we could violate this covenant in the future. 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 covenant in the future. 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 PCB line of credit to fund our loan to DCE if this were to occur. We were in compliance with all of the covenants as of June 30, 2009.

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Contractual Obligations

        The following represents the scheduled maturities of our contractual obligations as of June 30, 2009:

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(a)

Consists of long-term debt and capital lease obligations to finance equipment purchases, including interest.

(b)

Consists of various space and ground leases for our California LNG plant, offices and fueling stations as well as leases for equipment.

(c)

The amounts in the table represent our estimates for our fixed LNG purchase commitments under two "take or pay" contracts. In October 2007, we entered into a 10-year contingent take-or-pay commitment for 45,000 LNG gallons per day from an LNG plant to be constructed in Arizona, which commitment is not reflected in the table above because the obligation is contingent on the completion of construction of the LNG plant, which is anticipated to occur in the third quarter of 2009.

(d)

Consists of our obligations to fund various fueling station construction projects, net of amounts funded through June 30, 2009, and excluding contractual commitments related to station sales contracts.

Off-Balance Sheet Arrangements

        At June 30, 2009, we had the following off-balance sheet arrangements:

•

outstanding surety bonds for construction contracts and general corporate purposes totaling $7.6 million,



•

two take-or-pay contracts 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 or index-plus prices subject to a price cap.

        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 contracts with two vendors to purchase LNG that require us to purchase minimum volumes from the vendors. One of the contracts expired in July 2009 and the other contract expires in June 2011. The minimum commitments under these two contracts are included in the table set forth under "Take-or-pay" LNG purchase contracts above. In October 2007, we entered into a contingent take-or-pay contract from an LNG plant that is not included in the table above as it is contingent on the LNG plant being constructed. We anticipate construction of the plant will be completed in the third quarter of 2009.

        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 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. The leases generally qualify as sales-type leases for accounting purposes, which result in our customers, the lessees, reflecting the property and equipment on their balance sheets.

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 60% of our cost of sales for 2008 and 44% of our cost of sales for the six months ended June 30, 2009. Prices for natural gas over the nine-year and six-month period from December 31, 1999 through June 30, 2009, 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 June 30, 2009, the NYMEX index price of natural gas was $3.54 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 SFAS 133. Under this standard, the accounting for changes in the fair value of a derivative depends upon whether it has been designated 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 SFAS 133 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

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hedge accounting. During the six month period ended June 30, 2009, we had certain 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 changing market conditions. The net effect of the realized and unrealized gains and losses related to these derivative instruments for the year ended December 31, 2006 was a $79.0 million decrease to pre-tax income. We did not have any futures contracts outstanding during the year ended December 31, 2007. In an effort to mitigate the volatility in our earnings related to futures 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 SFAS 133, 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 futures contracts we hold as of June 30, 2009 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 June 30, 2009 ($3.54 per Mcf), we could expect a corresponding fluctuation in the value of the contracts of approximately $1.4 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 the 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. We are currently being audited by the IRS for tax years 2005 through 2007. 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 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

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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.

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 2008 Annual Report 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 six month period ended June 30, 2009, we incurred pre-tax losses of $13.2 million, which included derivative losses of $2.4 million. In 2006, 2007 and 2008 we incurred pre-tax losses of $89.8 million, $7.7 million, and $44.3 million, respectively. Our loss for 2006 included $79.0 million in derivative losses and our loss for 2008 included $18.6 million in expenses associated with our support for Proposition 10, the California Alternative Fuel Vehicles and Renewable Energy ballot initiative. For the six month period ended June 30, 2009, our loss was decreased by our receipt of approximately $8.1 million of revenue from federal fuel tax credits. During 2007 and 2008, our losses were decreased by our receipt of approximately $17.0 million and $17.2 million of revenue, respectively, from federal fuel tax credits. The law providing for the fuel tax credits is scheduled to expire 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.

Decreases in the price of oil, gasoline and diesel fuel may slow the growth of our business and negatively impact our financial results.

        Prices of oil, gasoline and diesel fuel have declined rapidly from summer 2008 levels. 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 $69.89 per barrel on June 30, 2009. 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 $2.79 per gallon at June 30, 2009 and average retail prices for gasoline in California have declined from a high of $4.59 per gallon in June 2008 to $2.98 per gallon at June 30, 2009. 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 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 $2.05 per diesel gallon equivalent at June 30, 2009 and our retail prices for CNG fuel sold in the Los Angeles Basin decreased from a high of $3.30 per GGE in July of 2008 to $2.30 per GGE at June 30, 2009. Lower fuel prices for CNG and LNG also will reduce our revenues.

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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 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 $7.7 million of the line of credit from PCB as of June 30, 2009. 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 in the future. Also, beginning with the quarter ending June 30, 2009, we are required to maintain a debt service ratio, as defined, of 1.5 to 1.0. Should our operating results not materialize as planned, we could violate this covenant in the future. 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 PCB line of credit to fund our loan to DCE if this were to occur.

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. Recent and significant volatility in oil and gasoline prices demonstrate that it is difficult to predict future transportation fuel costs. The decline in the price of oil, diesel fuel and gasoline from summer 2008 levels has reduced the economic advantages that our existing or potential customers may realize by using less expensive CNG or LNG fuel as an alternative to gasoline or diesel. The reduced prices for gasoline and diesel fuel and continuing uncertainty about fuel prices, combined with higher costs for natural gas vehicles, may cause potential customers to delay or reject converting their fleets to run on natural gas. In that event, our growth 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 the end of 2008, 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 August 1, 2009, the NYMEX index price for natural gas was $3.37 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 a futures contract or with an ineffective futures contract that does not fully mitigate 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

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vehicle fuel. Conversely, lower natural gas prices reduce our revenues. 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. The recent economic recession and increased domestic natural gas supplies have contributed to significant and rapid declines in the price of natural gas.

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 16,000 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. In addition, various lawsuits have been filed to block parts of the Clean Trucks Program which may delay the program's implementation. 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. 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 have a detrimental effect on the U.S. natural gas vehicle industry, which, in turn, could slow our growth and adversely affect our business.

Our growth depends in part on tax and related government incentives for clean burning fuels. A reduction in these incentives would increase the cost of natural gas fuel and vehicles for our customers and could 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 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, is scheduled to expire December 31, 2009. Based on the service relationship we have with our customers, either we or our customers are able to claim the credit. In 2007 and 2008, we recorded approximately $17.0 million and $17.2 million of revenue, respectively, related to fuel tax credits, representing approximately 14.5% and 13.7%, respectively, of our total revenue during the period. For the six-month periods ended June 30, 2008, and June, 30, 2009, we recorded $9.1 million and $8.1 million of revenue, respectively, related to fuel tax credits, representing approximately 14.3% and 13.9%, respectively, of our total revenue during the period. The failure to extend the federal excise tax credit for natural gas, or the repeal of federal or state tax credits for the purchase of natural gas vehicles or natural gas fueling equipment, could have a detrimental effect on the natural gas vehicle industry, which, in turn, could adversely affect our business and results of operations. In addition, if grant funds were no longer available under existing government programs, the purchase of or conversion to natural gas vehicles and station construction could slow and our business and results of operations could be adversely affected. Any reduction in tax revenues associated with an economic recession or slow-down could result in a significant reduction in funds available for government grants that support vehicle conversion and station construction and impair our ability to grow our business.

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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 summer 2008 levels 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 the 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 our ability to grow our business.

We may need to raise debt or equity capital to fund increased capital expenditures, unanticipated expenses or for any potential acquisitions, and an inability to access the capital markets may impair our ability to invest in our business.

        In order to fund unanticipated capital expenditures, expenses, or investments, or to provide resources for potential acquisition activity, we may need to pursue additional equity or debt financing options, which may not be available on terms favorable to us or at all. Recent economic turmoil and lack of liquidity in the debt capital markets and volatility and lower prices in the equity capital markets have adversely affected capital raising opportunities. If we are unable to obtain debt or equity financing in amounts sufficient to fund any unanticipated capital expenditures, unanticipated expenses, investments or potential acquisition activity, we will be forced to suspend or curtail these capital expenditures or postpone or delay the investments or potential acquisitions or other strategic transactions, which could harm our business, results of operations, and future prospects.

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 fuel 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.

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. Currently, 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 automobile manufacturer that makes natural gas powered passenger vehicles, and manufacturers of medium and heavy-duty vehicles produce only a narrow range and number of natural gas vehicles. The technology utilized in some of the heavy-duty vehicles that run on LNG is also relatively new and has not been

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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, it may delay or impair the growth of our LNG fueling business. 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 sales may be restricted, even if there is demand.

There are a small number of companies that convert vehicles to operate on natural gas, which may restrict our sales.

        Conversion of vehicle engines from gasoline or diesel to natural gas is performed by only a small number of vehicle conversion suppliers that must meet 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 which could discourage our potential customers from purchasing converted vehicles that run on natural gas. Without an increase in vehicle conversion options, vehicle choices for fleet use will remain limited and our sales may be restricted, even if there is demand.

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 ability to compete with other alternative fuels.

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 where it is a byproduct of their primary natural gas production. 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.

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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. An LNG supply interruption would also limit our ability to expand LNG sales to new 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, our operating margins will decrease on those sales.

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

        Some of our LNG supply agreements have take or pay commitments and our California LNG liquefaction plant has land lease and other fixed operating costs regardless of production and sales levels. Should the market demand for LNG decline 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 and negatively impact our margins.

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

        Two third-party LNG suppliers, Williams Gas Processing Company and ExxonMobil Corporation, supplied approximately 47% of the LNG we sold for the year ended December 31, 2007 and supplied 49% of the LNG we sold for the year ended December 31, 2008. For the six-month period ended June 30, 2009, Williams Gas Processing Company and ExxonMobil Corporation supplied approximately 26% of the LNG we sold. Under certain circumstances, Williams Gas Processing Company may terminate our supply contract on short notice. Williams may also significantly increase the price of LNG we purchase upon 24 hours' notice if Williams' costs to produce LNG increases, and we may be required to reimburse Williams Gas Processing Company for certain other expenses. Our contract with Williams Gas Processing Company, which supplied 32% of the LNG we sold for the year ended December 31, 2007, 29% for the year ended December 31, 2008, and 11% for the first six months of 2009, expires on June 30, 2011. Our contract with ExxonMobil Corporation, which supplied 15% of the LNG we sold for the year ended December 31, 2007, 20% for the year ended December 31, 2008, and 15% for the first six months of 2009, expired July 31, 2009. 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.

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, pipeline capacity, equipment failure, liquefaction production or delivery, 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.

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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 as 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. If the use of natural gas vehicles increases, these companies may find it more attractive to enter the market for natural gas vehicle fuels and we may experience increased pricing pressure, reduced operating margins and fewer expansion opportunities.

We are in the process of commencing operations at a new LNG liquefaction plant, which could cost more to operate than we estimate and divert resources and management attention.

        We are in the initial stages of operating our LNG liquefaction plant in California, which began producing LNG in November 2008. The implementation and operation of any plant of this nature has inherent risks. Permitting, environmental issues, a lack of materials and a lack of human resources, among other factors, could complicate our ability to operate the LNG liquefaction plant and affect the operation of the plant. The new facility could also present increased financial exposure through start-up delays, repairs and incomplete production capability. If the new plant has higher than expected operating costs and is not able to produce expected amounts of LNG, we may be forced to sell LNG at a price below production costs and we may lose money. Additionally, if the quality of LNG produced at the plant does not meet contractual specifications, our customers may not be required to purchase it, which would harm our business.

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 or production 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, we expect to purchase futures contracts to hedge our exposure to variability related to our fixed price contracts. However, such contracts may not be available or we may not have sufficient financial resources to secure such contacts. 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 June 30, 2009, we were economically hedged with respect to four of our fixed price contracts with our customers.

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 or price cap 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

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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. At June 30, 2009, we had $2.6 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 SFAS 133, which requires us to value our futures contracts at fair market value in our financial statements. Our futures contracts historically 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 SFAS 133, but there can be no assurances that we will be successful in doing so. At June 30, 2009, 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. For example, we experienced a derivative gain of $33.1 million and $5.7 million for the three months ended September 30, 2005 and June 30, 2008, respectively, and experienced derivative losses of $19.9 million, $0.3 million, $65.0 million, $13.7 million, $6.0 million and $0.3 million for the three months ended December 31, 2005, March 31, 2006, September 30, 2006, December 31, 2006, September 30, 2008 and December 31, 2008, respectively. We had no derivative gains or losses for the three months ended June 30, 2006, March 31, 2007, June 30, 2007, September 30, 2007, December 31, 2007, March 31, 2008, March 31, 2009 and June 30, 2009. 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 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

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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 operations entail inherent safety and environmental risks that may result in substantial liability to us.

        Natural gas operations 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. 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 exploded. 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.

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 and 2008, sales in California accounted for 40% and 45% respectively, and sales in Arizona accounted for 20% and 14%, respectively, of the total amount of gallons we delivered. For the six month period ended June 30, 2009, sales in California and Arizona accounted for 50% 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 on average 60% 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 as their sole source of income, which may make it difficult for us to recover the collateral in a bankruptcy proceeding. The continued disruption in the credit markets may further reduce the amount of capital available to us and an economic recession or continued economic contraction may increase the rate of default by borrowers, leading to an increase in losses on our loan portfolio. As of June 30, 2009, we had $3.7 million outstanding in loans provided to customers to finance natural gas vehicle purchases.

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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 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. At June 30, 2009, we had $4.2 million in aggregate deposits outstanding on natural gas vehicles which are described below.

        In July 2006, we entered into an agreement with Inland Kenworth, Inc. (Inland) pursuant to which we agreed to deposit certain amounts with Inland, as security for a guarantee, to fund the acquisition by Kenworth Truck Company ("Kenworth") of 100 LNG trucks. At June 30, 2009, we had outstanding $1.5 million of deposits under this agreement. We also entered into two deposit agreements with Westport Innovations, Inc. ("Westport") in 2007 to facilitate the production of LNG fuel systems for installation in the tractors purchased by Inland. At June 30, 2009, we had outstanding a total of $1.3 million on deposits made to Westport under these agreements. Repayment of these deposits will occur incrementally upon the sale of the converted tractors to customers; however, to the extent an LNG fuel system incorporated into a tractor is not sold within 24 months of the effective date of the applicable deposit agreement (or such other time period as is agreed by both us and Westport), Westport is not obligated to repay any of the deposit with respect to such LNG fuel systems. In addition, we have approximately $1.4 million on deposit at June 30, 2009 to secure the availability of 57 Honda Civic natural gas vehicles.

We have significant contracts with federal, state and local government entities, which 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 two-thirds of our revenues from 2006 through 2008. 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. Further, 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 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

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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 two-thirds of our revenues from 2006 through 2008.

        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. However, there is 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 impact of 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 was taken offline for repairs that were completed on July 2, 2009. Future operational upgrades or complications in the operations of the facility could require additional shut downs, 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 and $6.4 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 and June 30, 2009, respectively. Our quarterly results may fluctuate significantly as a result of a variety of factors, many of which are beyond our control. 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

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gasoline and diesel, changes in our pricing policies or those of our competitors, the costs related to the acquisition of assets or businesses, regulatory changes, expenses for ballot initiatives that could impact our business 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, 2009 and November 3, 2010, the exercise price per share of the Series I warrants could be reduced if the then current market price is sufficiently less than the then exercise price for the Series I warrants. In such an instance, the exercise price would reset to 120% of the then current market price so long as such resulting price is less than the then 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. At August 5, 2009, 59,692,712 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 June 30, 2009, there were 9,259,052 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 June 30, 2009, 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. On December 1, 2008, Warren I. Mitchell, our Chairman of the Board, entered into a Rule 10b5-1 Sales Plan with a broker to sell shares of our common stock that may be acquired upon the exercise of stock options. Under the plan, the broker may sell up to 2,000 shares of common stock each month, beginning in January 2009, provided that the price per underlying share is at or above $10.00 on the Nasdaq Global

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Market. All sales of common stock under the plan will be reported through appropriate filings with the SEC.

A majority 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 June 30, 2009 and August 7, 2009, Boone Pickens and affiliates (including Madeleine Pickens, his wife) beneficially owned in the aggregate approximately 53.9% and 46.5%, respectively, 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 also 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.

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

        None.

Item 3.—Defaults upon Senior Securities

        None.

Item 4.—Submission of Matters to a Vote of Security Holders

        Our annual meeting of stockholders was held on May 12, 2009. The stockholders elected seven members to our Board of Directors to serve until the next annual meeting of stockholders or until their respective successors have been duly elected and qualified. In addition, the stockholders ratified the appointment of KPMG LLP as our independent registered public accounting firm for the fiscal year ending December 31, 2009 and approved an amendment to our Amended and Restated 2006 Equity Incentive Plan to increase the number of shares of our common stock authorized for issuance under the plan from 9,390,500 shares to 10,890,500 shares.

        The number of shares voting as to the above issues is set forth below.

2.    The stockholders ratified the selection of KPMG LLP as our independent registered public accounting firm for the fiscal year ending December 31, 2009, with voting as follows: 43,134,761 for; 289,674 against; and 126,158 abstain.

3.    The stockholders approved an amendment to our Amended and Restated 2006 Equity Incentive Plan to increase the number of shares of our common stock authorized for issuance under the plan from 9,390,500 shares to 10,890,500 shares, with voting as follows: 22,802,423 for; 4,975,540 against; 77,442 abstain; and 15,358,542 broker non-votes.

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Item 5.—Other Information

        None.

Item 6.—Exhibits

(a)

Exhibits

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*

Filed herewith.

†

Confidential treatment has been requested for certain portions of Exhibit 10.50 under CFR §§ 230.24b-2 and 200.80(b)(4).

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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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