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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

FORM 10-Q

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

For the quarterly period ended March 31, 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 May 4, 2009, there were 50,238,212 shares of the registrant's common stock, par value $0.0001 per share, issued and outstanding.

CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES
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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 March 31, 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 Ended

March 31, 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 Three Months Ended March 31, 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. Clean Energy operates or supplies approximately 175 natural gas fueling locations in California, Texas, Colorado, Maryland, New York, New Mexico, Nevada, Washington, Massachusetts, Georgia, Wyoming, Arizona, Ohio and Oklahoma 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 the 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 months ended March 31, 2008 and 2009. All intercompany accounts and transactions have been eliminated in consolidation. The three month periods ended March 31, 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 ("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.

Note 2—Acquisition

        On August 15, 2008, Clean Energy 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 Clean Energy 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

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 2—Acquisition (Continued)

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 to finance its acquisition of its membership interests in DCE. The Company also obtained a $12.0 million line of credit from PlainsCapital Bank 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 PlainsCapital Bank loan. As of March 31, 2009, the Company had borrowed $7.8 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 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 4—Natural Gas Derivative Financial Instruments (Continued)

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 has entered into futures contracts that did qualify for hedge accounting. The Company's futures contracts at March 31, 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 March 31, 2009, all of the Company's futures contracts qualified for hedge accounting. The Company did not own any futures contracts during the first three months of 2008.

        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 gains of approximately $33,000 in accumulated other comprehensive income for the three month period ended March 31, 2009 related to its futures contracts. The liability for the Company's futures contracts of approximately $621,000 at March 31, 2009 is included in accrued liabilities on the Company's condensed consolidated balance sheet at March 31, 2009. The Company's ineffectiveness related to its futures contracts during the three month period ended March 31, 2009 was insignificant. For the three month period ended March 31, 2009, the Company recognized losses of approximately $500,000 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 March 31, 2009, the Company had $1.1 million of margin deposits related to its futures contracts covering approximately 1.6 million gallons of fuel, all of which were current and recorded in prepaid expenses and other current assets in the accompanying condensed consolidated balance sheet as of March 31, 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 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

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

        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 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 March 31, 2009 consisted of the following:

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 7—Land, Property and Equipment

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

Note 8—Investments in Other Entities

        Through March 31, 2009, the Company invested approximately $5.0 million in The Vehicle Production Group LLC ("VPG"), a company that is developing a natural gas vehicle made in the United States for taxi and paratransit use. The Company committed to fund up to $10 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 March 31, 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.

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 9—Accrued Liabilities

        Accrued liabilities at December 31, 2008 and March 31, 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 PlainsCapital Bank. 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 PlainsCapital Bank to finance capital improvements of the DCE processing facility and to pay certain costs and expenses related to the acquisition and the PlainsCapital Bank loans (the "Facility B Loan"). As of March 31, 2009, the Company had borrowed $7.8 million under the Facility B Loan. The Company may request funds up to $12.0 million 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 March 31, 2009, the unamortized balance of the facility fee was $262,500. 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 is due and payable quarterly commencing on September 30, 2008. The principal amount of the Facility B Loans 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 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 10—Long-term Debt (Continued)

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 ending 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. The Company is in compliance with the covenants as of March 31, 2009.

        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 ending 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 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 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 March 31, 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. Upon closing of the acquisition of DCE, the Company funded approximately $714,000 under the agreement. The funds were obtained as part of the initial $4.2 million funded under the Facility B Loan with PlainsCapital Bank to the Company. Interest on the unpaid balance accrues at a rate of 12% per annum and is payable quarterly beginning 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 10—Long-term Debt (Continued)

results in a cross-default of the Company's Credit Agreement with PlainsCapital Bank. 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 March 31, 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 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:

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

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 March 31, 2008 and 2009, respectively, as the inclusion of the securities would be anti-dilutive to the calculation. The amounts outstanding as of March 31, 2008 and 2009 for these instruments are as follows:

Note 13—Comprehensive Income (Loss)

        The following table presents the Company's comprehensive loss for the three months ended March 31, 2008 and 2009:

        Included in comprehensive loss at March 31, 2009 is approximately $386,000 of income related to the non-controlling interest in DCE.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

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 three months ended March 31, 2009:

        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 three months ended March 31, 2009 was $3.98.

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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

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

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 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 three months ended March 31, 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 March 31, 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.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 18—Fair Value Measurements (Continued)

annually. Accordingly, the Company's adoption of SFAS 157 was limited to financial assets and liabilities.

        During the three months ended March 31, 2009, the Company's financial instruments consisted of natural gas futures contracts and the Series I warrants (see note 19). 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 the Series I warrants are recorded in other long-term liabilities in the accompanying condensed consolidated balance sheet at March 31, 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 March 31, 2009:

Note 19—Recently Adopted Accounting Changes

        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 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 19—Recently Adopted Accounting Changes (Continued)

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 of 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 Asset. 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 (EITF) reached a consensus in EITF No. 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity's Own Stock (EITF No. 07-5). The Task Force 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.

Note 20—Subsequent Events

        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 located at McCommas Bluff in Dallas Texas. 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

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 20—Subsequent Events (Continued)

•

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 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 of $3.80 per MMBtu as quoted on NYMEX for May delivery on April 3, 2009.

        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).

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 20—Subsequent Events (Continued)

        On April 28, 2009, the Company purchased certain natural gas futures contracts to attempt to hedge its exposure to cash flow variability related to the fixed-price component of two liquefied natural gas (LNG) supply contracts for which it had submitted fixed-price bids. The Company has not been awarded the contracts; however, based on information released by the potential customers, the Company believes it has submitted the lowest price in the competitive bidding process. The Company has also received a staff recommendation supporting its bid for the larger of the two contracts. If the Company is successful in being awarded the supply contracts, performance is anticipated to begin on July 1, 2009 and September 6, 2009, respectively, on the two contracts. The futures contracts have the effect of enabling the Company to purchase natural gas at fixed prices each month from July 2009 through August 2012, which is the expected fixed-price term of the potential supply contracts. One of the supply contracts calls for the sale of approximately 12,000,000 LNG gallons annually for all three years of the contract, and the other supply contract calls for the anticipated sale of approximately 700,000 LNG gallons in the first year, 500,000 LNG gallons in the second year and 300,000 LNG gallons in the third year of the contract. The futures contracts cover the purchase of an average of approximately 80,000 MMBtus of natural gas per month to hedge against the cost of the fixed price LNG delivery obligations. To purchase the futures contracts, the Company was required to make an initial margin deposit of $1,236,000. The Company may be required to make additional deposits if it incurs losses related to the futures contracts. The Company will attempt to qualify the futures contracts for hedge accounting under SFAS No. 133, but there can be no assurances the Company will be able to do so.

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 three month periods ended March 31, 2008 and 2009 were approximately $4.7 million and $4.1 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 (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 annual report on Form 10-K filed with the SEC on March 16, 2009, 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 annual report on Form 10-K. In preparing this MD&A, we presume that readers have access to and have read the MD&A in our Annual report on Form 10-K, pursuant to Instruction 2 to paragraph (b) of Item 303 of Regulation S-K. We undertake no duty to update any of these forward-looking statements after the date of filing of this report to conform such forward-looking statements to actual results or revised expectations, except as otherwise required by law.

        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 months ended March 31, 2008 and 2009:

        Key trends in 2006, 2007, and 2008.    Vehicle fleet demand for natural gas fuels increased during the three year period ended December 31, 2008. 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 173 at March 31, 2009 (a 17.7% 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 during these periods. Our cost of sales also increased during these periods, 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.

Recent developments.

        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 located at McCommas Bluff in Dallas Texas. 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

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        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 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 of $3.80 per MMBtu as quoted on NYMEX for May delivery on April 3, 2009.

        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).

        On April 28, 2009, we purchased certain natural gas futures contracts, which we refer to as the futures contracts below, to attempt to hedge our exposure to cash flow variability related to the fixed-price component of two liquefied natural gas (LNG) supply contracts for which we have submitted fixed-price bids. We have not been awarded the contracts; however, based on information released by the potential customers, we believe we have submitted the lowest price in the competitive bidding process. We have also received a staff recommendation supporting our bid for the larger of the two contracts. If we are awarded the supply contracts, performance is anticipated to begin on July 1, 2009 and September 6, 2009, respectively. While we have not received notification that we have been awarded the contracts, due to the fact that the contract prices are fixed, as well as the fact that we believe natural gas prices may rise between now and the time we might be awarded the contracts, the derivative committee of our board of directors concluded it was advisable to purchase the futures contracts in advance of any contract award. The futures contracts have the effect of enabling us to purchase natural gas at fixed prices each month from July 2009 through August 2012, which is the expected fixed-price term of the potential supply contracts. One of the supply contracts calls for the sale of approximately 12,000,000 LNG gallons annually for all three years of the contract, and the other supply contract calls for the anticipated sale of approximately 700,000 LNG gallons in the first year, 500,000 LNG gallons in the second year and 300,000 LNG gallons in the third year of the contract. The

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futures contracts cover the purchase of an average of approximately 80,000 MMBtus of natural gas per month to hedge against the fixed price LNG delivery obligations. To purchase the futures contracts, we were required to make an initial margin deposit of $1,236,000. We may be required to make additional deposits if we incur losses related to the futures contracts.

        The purchase of the futures contracts was in accordance with the revised natural gas hedging policy adopted by our board of directors in May, 2008, 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 herein by reference.

        Until such time as we are awarded and enter into the supply contracts, we do not anticipate trying to qualify the futures contracts for hedge accounting as cash flow hedges under SFAS No. 133. As a result, we will be required to record directly in our statement of operations any changes in the fair market value of these contracts that may occur from April 28, 2009 through the earlier to occur of (1) our entry into the fixed-price supply contracts and success in qualifying the futures contracts for hedge accounting under SFAS No. 133, or (2) the sale of the futures contracts. Until such time as the futures contract qualify for hedge accounting as cash flow hedges under SFAS No. 133, an increase or decrease of 10% in the weighted average price of the futures contracts would result in a gain or loss, respectively, of approximately $1.8 million in the fair market value of the futures contracts.

        If we are awarded and enter into the supply contracts, (1) we will attempt to qualify the futures contracts for hedge accounting as cash flow hedges under SFAS No. 133, but there can be no assurances we will be successful in doing so, and (2) we anticipate that we will hold the futures contracts for the duration of the relevant contract term consistent with the revised natural gas hedging policy adopted by our board of directors in May 2008. If we are not awarded or fail to enter into either supply contract, we intend to sell the futures contracts related to such supply contract in an orderly fashion.

        We purchased the futures contracts from Sempra Energy Trading Corp. pursuant to the terms of the ISDA Master Agreement dated March 23, 2006 between us and Sempra, including the ISDA Credit Support Index to the Schedule to the ISDA Master Agreement dated March 23, 2006, which documents are attached as Exhibits 10.13 and 10.14, respectively, to the Form S-1 Registration Statement (File No. 333-137124) we filed with the SEC on September 6, 2006. These documents are incorporated herein by reference.

        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 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

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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, 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.

        In addition, the economic recession that began during 2008 has resulted in decreased demand for vehicle fuel generally, which reduced our sales of LNG and CNG fuel during 2008. 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. 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 may 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 PlainsCapital Bank. We borrowed $18.0 million to finance the acquisition and entered into a $12.0 million line of credit from PlainsCapital Bank to provide capital to DCE, primarily for capital expenditures, and to pay certain costs and expenses of the acquisition and the loans. As of May 4, 2009, approximately $4.2 million is available under the line of credit from PlainsCapital Bank to provide further capital to DCE. 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 received net proceeds of approximately $32.5 million.

        Our current business plan calls for approximately $20.9 million in additional capital expenditures from April 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 $0.5 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 line of credit from PlainsCapital Bank. We may also elect to invest additional amounts in expansion of our California LNG plant, station construction for new or existing customers that are not currently under contract, or for other acquisitions or investments in companies or assets in

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the natural gas fueling infrastructure, services and production industries. We will need to raise additional capital as necessary to fund expansion of our California LNG plant, additional station construction, acquisitions or other capital expenditures or investments which are not budgeted for in our 2009 business plan and we anticipate we will seek to raise capital during 2009. For more information, see "Liquidity and Capital Resources" below. 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 expand our business and generate increased revenues.

        Volatility in operating results related to futures contracts.    Historically, we have purchased futures contracts from time to time to help mitigate our exposure to natural gas price fluctuations in current periods and in future periods. Prior to 2008, our futures contracts did not qualify for hedge accounting under SFAS No. 133, and in 2008, some of our contracts qualified for hedge accounting under SFAS No. 133 and some did not. 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 were $78,994,947, $0 and $611,175, respectively. We have no derivative (gains) losses for the three months ended March 31, 2008 and 2009 related to futures contracts. 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 three months ended March 31, 2009, CNG and biomethane (together) represented 71% and LNG represented 29% 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 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.

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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 Volumetric Excise Tax Credit ("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." 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.

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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. As of March 31, 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 quarter ended March 31, 2009, DCE generated approximately $1.8 million and $0.6 million, respectively, in revenue from sales of biomethane, all of which is included in our condensed consolidated statements of operations.

Volatility of Earnings and Cash Flows

        Our earnings and cash flows historically have fluctuated significantly from period to period based on our futures activities, as all but a few of our futures contracts have 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 and March 31, 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 can not 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 contacts. Futures contracts are valued daily, and if our contracts are in loss positions at the end of a trading day, our broker will transfer the amount of the losses from our margin account to a clearinghouse. If at any time the funds in our margin account drop below a specified maintenance level, our broker will issue a margin call that requires us to restore the balance. Consequently, these payments could significantly impact our cash balances. At March 31, 2009, we had $1.1 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.

Debt Compliance

        Our credit agreement with PlainsCapital Bank ("Credit Agreement") requires us to comply with certain covenants. We may not incur indebtedness or liens except as permitted by the Credit

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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 ending 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 March 31, 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 ending 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.

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 annual report on Form 10-K for the year ended December 31, 2008, 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.

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        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 quarter 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 annual report on Form 10-K for the year ended December 31, 2008.

Recently Issued Accounting Pronouncements

        None.

Results of Operations

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

Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2008

        Revenue.    Revenue increased by $0.3 million to $30.2 million in the three months ended March 31, 2009, from $29.9 million in the three months ended March 31, 2008. We experienced a $5.1 million

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increase in station construction revenues between periods primarily due to the completion of a CNG station for the Orange County Transportation District. This increase was offset by a decrease in our average price per gallon we charged between periods. Our effective price per gallon was $1.14 in the three months ended March 31, 2009, which represents a $0.29 per gallon decrease from $1.43 in the three months ended March 31, 2008. The decrease was primarily due to the decreased price of natural gas in the first quarter of 2009, upon which a significant amount of our revenues are based. Revenue also decreased between periods as we recorded $4.1 million of revenue related to fuel tax credits in the first quarter of 2009, compared to $4.7 million in the first quarter of 2008. These gas sales decreases were offset by the increase in the number of gallons delivered between periods from 17.6 million gasoline gallon equivalents to 18.3 million gasoline gallon equivalents. The increase in volume was primarily from an increase in biomethane sales and CNG sales of 0.9 million and 0.5 million gallons, respectively. The biomethane volume related to our 70% share of the biomethane sales of DCE. Two of our new transit customers (Regional Transportation Commission of Nevada and Regional Transit Authority of Ohio) and one of our new refuse customers (Brookhaven Carters) together accounted for 0.4 million of the CNG volume increase. Offsetting these increases is a 0.7 million gallon decrease in LNG volumes, which was primarily due to the loss of a portion of the City of Phoenix LNG supply contract that began July 1, 2008.

        Cost of sales.    Cost of sales decreased by $0.8 million to $21.6 million in the three months ended March 31, 2009, from $22.4 million in the three months ended March 31, 2008. Our cost of sales primarily decreased between periods as a result of our effective cost per gallon declining by $0.35 per gallon to $0.93 in the three months ended March 31, 2009, primarily due to the decreased price of natural gas in the first quarter of 2009. Offsetting this decreases was a $0.7 million increase in costs related to delivering more volume between periods. We also experienced a $4.6 million increase in station construction costs between periods.

        Derivative (gain) loss.    We recorded a derivative loss of $0.2 in the first quarter of 2009 upon the adoption of EITF No. 07-5 during the period that requires us to mark-to-market our Series I warrants (see note 19 to our condensed consolidated financial statements contained elsewhere herein) at the end of each reporting period.

        Selling, general and administrative.    Selling, general and administrative expenses were consistent between periods. Our marketing expenses decreased $1.4 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 first quarter of 2009 as we did in the first quarter of 2008. The decrease was offset by $1.0 million increase in stock option expense between periods, primarily due to options granted to our employees in December 2008 and January 2009. We also experienced a $0.4 million increase in salaries and benefits between periods related to the hiring of additional employees. Our employee headcount increased from 128 at March 31, 2008 to 138 at March 31, 2009.

        Depreciation and amortization.    Depreciation and amortization increased by $1.5 million to $3.6 million in the three months ended March 31, 2009, from $2.1 million in the three months ended March 31, 2008. This increase was primarily related to additional depreciation expense in the three months ended March 31, 2009 related to increased property and equipment balances between periods, primarily related to our expanded station network and our California LNG plant. Our March 31, 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.

        Interest income (expense), net.    Interest income (expense), net, decreased by $872,000 to $33,000 of expense for the three months ended March 31, 2009. This decrease was primarily the result of a decrease in interest income in the three months ended March 31, 2009 due to lower average cash balances on hand during the three months ended March 31, 2009. We also incurred interest expense of

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$0.1 million in the first 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 quarter of 2008.

        Other income (expense), net.    There was no significant change in other income (expense), net, between the three months ended March 31, 2009 and the three months ended March 31, 2008.

        Equity in gains (losses) of equity method investee.    Equity in gains (losses) of equity method investee increased by $162,000 to a $17,000 gain for the three months ended March 31, 2009 related to our 49% interest in our Peruvian joint venture.

        Noncontrolling interest in net income.    During the three months ended March 31, 2009, we recorded $0.4 million of income for the noncontrolling interest in the net income 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, cash and cash equivalents, the issuance of common stock, sometimes in association with the exercise of certain warrants that were callable at our option, and in 2006 a revolving line of credit with Boone Pickens, our majority stockholder. In May 2007, we completed our initial public offering of 10,000,000 shares of common stock at a public offering price of $12.00 per share. Net cash proceeds from the initial public offering were approximately $108.5 million, after deducting underwriting discounts, commissions and offering expenses. On August 15, 2008, in connection with our acquisition of 70% of the membership interests of DCE, we entered into a credit agreement with PlainsCapital Bank pursuant to which we have borrowed $18.0 million under a term loan and an additional $7.8 million (as of March 31, 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.

        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, and for working capital for our expansion. We may also seek to acquire companies or assets in the natural gas fueling infrastructure, services and production industries. We financed our operations in the first three months of 2009 primarily through cash on hand.

        At March 31, 2009, we had total cash and cash equivalents of $30.9 million, compared to $36.3 million at December 31, 2008.

        Cash provided by operating activities was $1.7 million for the three months ended March 31, 2009, compared to cash used in operating activities of $5.7 million for the three months ended March 31, 2008. The increase in operating cash flow resulted primarily from increased collections of accounts and other receivables between periods of $4.2 million and a $4.2 million net return of LNG truck deposits between periods. Offsetting these increases was a $2.4 million increase in accounts payable and accrued expense payments 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.

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        Cash used in investing activities was $9.7 million for the three months ended March 31, 2009, compared to $44.8 million for the three months ended March 31, 2008. Our purchases of property and equipment were $9.1 million during the first three months of 2009 compared to $14.8 million for the same period in 2008. We made an additional investment during the first three months of 2009 of $0.6 million in the Vehicle Production Group, LLC, a company developing a CNG taxi and a paratransit vehicle. In the first three months of 2008, we purchased $42.6 million of short-term investments with our initial public offering proceeds from May 2007, of which $12.5 million matured or were sold during the period. We did not have any short-term investments during the first three months of 2009.

        Cash provided by financing activities for the three months ended March 31, 2009 was $2.7 million, compared to $62,000 for the three months ended March 31, 2008. In February 2009, we borrowed an additional $3.1 million from PlainsCapital Bank to fund capital expenditures for DCE's landfill plant upgrade. This increase in cash was offset by repayment of capital lease obligations and long-term debt of $0.4 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, 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 $20.9 million in additional capital expenditures from April 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 $0.5 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 May 4, 2009, we have provided our joint-venture subsidiary DCE with approximately $4.4 million in financing under our loan agreement with DCE and we anticipate that we will provide up to approximately $2.9 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 as we anticipate that we will fund all additional financing we provide to DCE through our $12.0 million Facility B loan with PlainsCapital Bank, which has approximately $4.2 million in remaining available credit as of May 4, 2009. We intend to fund our principal liquidity requirements, other than our loan to DCE, through cash and cash equivalents and cash provided by operations; however, we may pursue station construction opportunities that are not currently under contract or in our 2009 capital expenditure plan or seek to acquire or invest in companies or assets in the natural gas fueling infrastructure, services and production industries. We may also decide to invest in expanding our California LNG plant or other LNG production assets. We anticipate that we will seek to raise additional capital during 2009 to provide funding for any such acquisitions, strategic transactions, increases in station construction activity, expansion of our California LNG plant or other unanticipated capital expenditures. 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 PlainsCapital Bank 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

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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 PlainsCapital Bank would be applied to the balance due on the PlainsCapital Bank loans. We also would be unable to use the PlainsCapital 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 March 31, 2009.

Contractual Obligations

        The following represents the scheduled maturities of our contractual obligations as of March 31, 2009:

(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 second quarter of 2009.

(d)

Consists of our obligations to fund various fueling station construction projects, net of amounts funded through March 31, 2009, and excluding contractual commitments related to station sales contracts.

Off-Balance Sheet Arrangements

        At March 31, 2009, we had the following off-balance sheet arrangements:

•

outstanding surety bonds for construction contracts and general corporate purposes totaling $5.6 million,



•

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

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•

operating leases where we are the lessee,



•

capital 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.

        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 expires in June 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 second 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 43% of our cost of sales for the three months ended March 31, 2009. Prices for natural gas over the nine-year and three-month period from December 31, 1999 through March 31, 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 March 31, 2009, the NYMEX index price of natural gas was $4.07 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.

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        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 hedge accounting. During the three month period ended March 31, 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 March 31, 2009 to hedge the fixed-price component of two LNG supply contracts. If the price of natural gas were to fluctuate (increase or decrease) by 10% from the price quoted on NYMEX on March 31, 2009 ($4.07 per Mcf), we could expect a corresponding fluctuation in the value of the contracts of approximately $82,000.

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 Securities and Exchange Commission'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.

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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. We are currently engaged in commercial litigation with an LNG supplier but we do not believe the outcome of the litigation will have a material adverse effect on our consolidated financial position or results of operations. During the course of our operations, we are also subject to audit by tax authorities for varying periods in various federal, state, local, and foreign tax jurisdictions. Disputes 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 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

        The risk factors included in our December 31, 2008 annual report on Form 10-K continue to apply to us, and describe risks and uncertainties that could cause actual results to differ materially from the results expressed or implied by the forward-looking statements contained in this Quarterly Report. The discussion below includes updated risk factors that could materially affect our business and results of operations. Except as discussed in the risk factors below, there have not been any material changes from the risk factors previously described in our December 31, 2008 annual report on Form 10-K.

Failure to comply with the terms of our Credit Agreement with PlainsCapital Bank could impair our rights in Dallas Clean Energy, LLC ("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 $18.0 million from PlainsCapital Bank to fund the acquisition and obtained a $12 million line of credit from PlainsCapital 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 $7.8 million of the line of credit from PlainsCapital Bank as of March 31, 2009. To secure our obligations under the Credit Agreement, we granted PlainsCapital Bank 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 PlainsCapital Bank 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 PlainsCapital Bank would be applied to the balance due on the PlainsCapital Bank loans. We also would be unable to use the PlainsCapital line of credit to fund our loan to DCE if this were to occur.

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We anticipate raising debt or equity capital to fund increased capital expenditures beyond those included in our 2009 capital budget and for any potential strategic transactions, and an inability to access the capital markets may impair our ability to expand our business

        We anticipate that, in order to fund capital projects beyond those included in our 2009 capital budget and to pursue potential strategic transactions as opportunities arise (which were not included in our 2009 capital budget), we will need to pursue additional equity or debt financing, which may not be available on terms favorable to us or at all. Our original 2009 capital plan anticipated $31.6 million of capital expenditures during 2009 and no amounts for acquisitions. While we believe that we have sufficient cash to fund our original 2009 capital plan during the remainder of the year, we anticipate that we will need to raise debt or equity capital during 2009 to have sufficient funds available to pursue strategic transactions and capital expenditures beyond our 2009 capital budget. We may pursue equity or debt financing options including, but not limited to, equipment financing, convertible promissory notes or commercial bank financing. Recent economic turmoil and severe lack of liquidity in the debt capital markets and volatility and rapidly falling prices in the equity capital markets have severely and adversely affected capital raising opportunities. If we are unable to obtain debt or equity financing in amounts sufficient to fund any additional capital expenditures, strategic transactions or unanticipated expenses, we will be forced to suspend or curtail our capital expenditure program or we may not pursue opportunities for strategic transactions, which would limit our ability to expand our business. In addition, the terms, conditions and prices of any equity or debt issuance may be dilutive to existing stockholders or poorly received in the investment community, which could cause the price of our commons stock to drop.

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

Use of Proceeds

        On October 28, 2008, the Company entered into a Placement Agent Agreement (the "Placement Agent Agreement") relating to the sale and issuance by the Company to select investors of up to 4,419,192 units (the "Units"), with each Unit consisting of (i) one share of the Company's common stock, par value $0.0001 per share, (ii) a warrant to purchase 0.75 shares of Common Stock (the "Series I Warrant"), and (iii) a warrant to purchase up to 0.2571 shares of Common Stock (the "Series II Warrant"). Our offering of common stock and warrants was effected through a Registration Statement on Form S-3 (File No. 333-152306) that was declared effective by the Securities and Exchange Commission on July 29, 2008. The price of each Unit was $7.92 per Unit. The transaction closed on November 3, 2008 and the Company issued 4,419,192 shares of common stock, Series I Warrants to purchase up to 3,314,394 shares of Common Stock, and Series II Warrants to purchase up to 1,136,364 shares of Common Stock. As of December 31, 2008, all of the Series II Warrants have been exercised. The Company received approximately $32.5 million after deducting the placement agents' fees and other offering expenses. As of March 31, 2009, we have used $1.6 million of the net proceeds from this offering for construction and installation of CNG and LNG stations.

Item 3.—Defaults upon Senior Securities

        None.

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

        None.

Item 5.—Other Information

        None.

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Item 6.—Exhibits

(a)

Exhibits

*

Filed herewith.

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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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Item 1.—Financial Statements (Unaudited)

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

Item 3.—Quantitative and Qualitative Disclosures about Market Risk
Item 4.—Controls and Procedures

Item 1.—Legal Proceedings
Item 1A.—Risk Factors
Item 2.—Unregistered Sales of Equity Securities and Use of Proceeds
Item 3.—Defaults upon Senior Securities
Item 4.—Submission of Matters to a Vote of Security Holders
Item 5.—Other Information
Item 6.—Exhibits