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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 September 30, 2008

Commission File Number: 001-33480

CLEAN ENERGY FUELS CORP.

(Exact name of registrant as specified in its charter)

3020 Old Ranch Parkway, Suite 200, 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. x

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 x

As of November 12, 2008, there were 50,195,471 shares of the registrant’s common stock, par value $0.0001 per share, issued and outstanding.

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

INDEX

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PART I. – FINANCIAL INFORMATION

Item 1. – Financial Statements (Unaudited)

Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Balance Sheets

December 31, 2007 and September 30, 2008 (Unaudited)

See accompanying notes to condensed consolidated financial statements.

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Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Statements of Operations

For the Three Months and Nine Months Ended

September 30, 2007 and 2008

(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 Nine Months Ended September 30, 2007 and 2008

(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 Alabama within the United States, and in British Columbia and Ontario within Canada. The Company also generates revenue through operation and maintenance agreements with certain customers, through building and selling or leasing natural gas fueling stations to its customers, and through financing its customers’ vehicle purchases. In April 2008, the Company opened its first compressed natural gas (“CNG”) station in Lima, Peru through the Company’s joint venture, Clean Energy del Peru.  In August 2008, the Company acquired 70% of the outstanding membership interests of Dallas Clean Energy, LLC (“DCE”). DCE owns a facility that collects, processes and sells landfill gas in Texas.

Basis of Presentation:  The accompanying interim unaudited condensed consolidated financial statements include the accounts of the Company and its subsidiaries, and, in the opinion of management, reflect all adjustments, which include only normal recurring adjustments, necessary to state fairly the Company’s financial position, results of operations and cash flows for the three and nine months ended September 30, 2007 and 2008. All intercompany accounts and transactions have been eliminated in consolidation. The three and nine month periods ended September 30, 2007 and 2008 are not necessarily indicative of the results to be expected for the year ending December 31, 2008 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, 2007 that are included in the Company’s Annual Report on Form 10-K filed with the SEC.

Reclassification:  A reclassification has been made to the presentation of the statement of cash flows for the nine months ended September 30, 2007 to conform to the current year presentation.  Deposits on liquified natural gas (“LNG”) trucks have been reclassified from prepaid expenses and other assets to a separate line item in the statement of cash flows for the nine months ended September 30, 2007.

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 DCE.  DCE 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 renewable biogas which may be used as a vehicle fuel.

The Company paid an aggregate of $19.1 million 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.

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 September 30, 2008, the Company had borrowed $4.2 million under the line of credit (see note 11).

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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 $21.3 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 year ended December 31, 2007 and the first nine months of 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. Cash and cash equivalents generally consist of cash, time deposits, commercial paper, money market funds and government and corporate debt securities with original maturity dates of three months or less. Such investments are stated at cost, which approximates fair value.

Note 4 — Short-Term Investments

Short-term investments, which are classified as “available for sale,” generally consist of commercial paper and government and commercial debt securities with original maturity dates between three and nine months. Short-term investments are marked-to-market at each period end with any unrealized gains or losses included in the condensed consolidated balance sheets under the line item accumulated other comprehensive income.  All of the short-term investments at December 31, 2007 matured or were sold during the nine months ended September 30, 2008.

Note 5 — Derivative Financial Instruments

The Company, in an effort to manage its natural gas commodity price risk exposures related to certain contracts, utilizes derivative financial instruments. The Company, from time to time, enters into natural gas futures contracts that are over-the-counter swap transactions that convert its index-based gas supply arrangements to fixed-price arrangements. The Company accounts for its derivative instruments in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (SFAS 133).  SFAS 133 requires the recognition of all derivatives as either assets or liabilities in the consolidated balance sheet and the measurement of those instruments at fair value.  Historically, the Company’s derivative instruments have not qualified for hedge accounting under SFAS 133.  The Company did not have any derivative instruments during the year ended December 31, 2007, but had certain futures contracts in place at September 30, 2008 to hedge a fixed-price LNG supply contract with a customer. The futures contracts at September 30, 2008 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.

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The Company marks to market its open futures position 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.  For the three and nine month periods ended September 30, 2008, the Company recorded losses of $6.0 million and $0.3 million, respectively, related to its futures contracts in the consolidated statements of operations.  These futures contracts were related to the portion of an LNG supply contract that the Company bid on but was not awarded.  The Company recorded unrealized losses of $1.1 million in accumulated other comprehensive income for the three months ended September 30, 2008 for the futures contracts applicable to the portion of the LNG supply contract it was awarded (see note 6).  The liability for these contracts is in accrued liabilities on the Company’s condensed consolidated balance sheet at September 30, 2008.  There was no ineffectiveness of the futures contracts recognized during the period.  The Company recognized losses of $0.2 million during the three and nine month periods ended September 30, 2008 related to futures contracts applicable to this supply contract.  Such amounts are included in cost of sales in the condensed consolidated statements of operations.

The Company is required to make certain deposits on its futures contracts, should any exist. At September 30, 2008, the Company had $0.8 million of margin deposits related to its futures contracts, all of which was classified as current as of September 30, 2008.

Note 6 — 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 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.

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 5) and, if the Company believed the price of natural gas would decline in the future, periodically sold such contracts.

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).

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The following table summarizes important information regarding the Company’s fixed price and price cap supply contracts under which it is required to sell fuel to its customers as of September 30, 2008:

This table does not include two 2.1 million LNG gallon per year renewal options beginning April 1, 2009 that one of our customers possesses related to an LNG price cap contract.  The contract contains a price cap of $7.50 per MMbtu on the SoCal Border Index.

(a)           Estimated volumes are in gasoline gallon equivalents for CNG contracts and are in LNG gallons for LNG contracts and represent the volumes we anticipate delivering over the remaining duration of the contracts.

(b)           Average prices are in gasoline gallon equivalents for CNG contracts and are in LNG gallons for LNG contracts. The average prices represent the natural gas commodity component in the customer’s contract.

At September 30, 2008, we estimate we will incur between $0.4 million and $0.5 million to cover the increased price of natural gas above the inherent price of natural gas embedded in our customer’s fixed price and price cap contracts over the duration of the contracts. These estimates were based on natural gas futures prices on September 30, 2008, and these estimates may change based on future natural gas prices and may be significantly higher or lower. Our estimated volumes under these contracts, in gasoline gallon equivalents, expire as follows:

This table does not include the two 2.1 million LNG gallon per year renewal options that one of our customer possesses related to an LNG price cap contract.

On April 18, 2008, the Company purchased certain natural gas futures contracts to attempt to economically hedge the Company’s exposure to cash flow variability related to the commodity component of an LNG supply contract for which the Company had submitted a fixed-price bid.  As previously disclosed in the Company’s Form 8-K dated June 19, 2008, the supply contract for which the futures contracts were purchased was awarded to a competitor of the Company.  The Company protested the award of the contract to its competitor and ultimately the Company was awarded a portion of the contract representing approximately one-third of the contract volumes.  In July 2008, the Company then sold the futures contracts related to the portion of the contract it was not awarded.  Due to the decrease in the price of natural gas between the date the futures contracts were purchased and the date they were sold, the Company ultimately realized a net loss of $0.3 million related to the sale of the futures contracts purchased with respect to the portion of the fixed-price contract that was not awarded to the Company.  The remaining futures contracts qualify for hedge accounting as cash flow hedges under SFAS 133 (see note 5).

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Note 7 — Other Receivables

Other receivables at December 31, 2007 and September 30, 2008 consisted of the following:

Note 8 — Land, Property and Equipment

Land, property and equipment at December 31, 2007 and September 30, 2008 are summarized as follows:

Note 9 — Investments in Other Entities

In August 2008, the Company invested approximately $3.2 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.  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 September 30, 2008, the $3.6 million outstanding under the Note would convert into approximately 47% of the outstanding equity interests of BAF if fully converted. The Company may, at the Company’s discretion, advance up to $2.4 million in additional funds to BAF under the Note. The Note bears interest at 5% per annum and is due August 30, 2010.

Note 10 — Accrued Liabilities

Accrued liabilities at December 31, 2007 and September 30, 2008 consisted of the following:

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Note 11 — 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 September 30, 2008, the Company had borrowed $4.2 million under the Facility B Loan.  The Company may request funds up to $12.0 million under the Facility B Loan through February 15, 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 September 30, 2008, the unamortized balance of the facility fee was $292,500.  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 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 minimum liquidity of not less than $6.0 million at each quarter end beginning December 31, 2008, maintain an accounts receivable balance, as defined, at each month end of not less than $10.0 million beginning August 31, 2008, maintain 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 at each quarter end beginning September 30, 2008, and a debt service ratio, as defined, of not less than 1.5 to 1 for each quarterly period beginning June 30, 2009.  If the Company defaults on the Credit Agreement, all of the obligations under the Credit Agreement will become immediately due and payable.

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.

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 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.

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

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                Principal payments under long-term debt and capital lease obligations for the annual periods ending September 30, are as follows:

Note 12 — Issuance of Common Stock

On September 24, 2008, the Company entered into a subscription agreement with Boone Pickens Interests, Ltd. pursuant to which the Company issued and sold a total of 319,488 shares of its common stock at a purchase price of $15.65 per share, the closing price of its common stock on the Nasdaq Global Market, for an aggregate purchase price of approximately $5.0 million.  Boone Pickens Interests, Ltd. is a limited partnership, the limited partner interest in which is owned collectively by certain trusts. Boone Pickens, a director of the Company and the Company’s largest stockholder, is the settlor of such trusts.

Note 13 — 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 September 30, 2007 and 2008, respectively, as the inclusion of the securities would be anti-dilutive to the calculation. The amounts outstanding as of September 30, 2007 and 2008 for these instruments are as follows:

Note 14 — Comprehensive Income (Loss)

                The following table presents the Company’s comprehensive loss for the nine months ended September 30, 2007 and 2008:

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Note 15 — 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 all stock option activity during the nine months ended September 30, 2008:

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants in 2008:

Based on these assumptions, the weighted average grant date fair value of options granted during the nine months ended September 30, 2008 was $8.57.

Note 16 — 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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Note 17 — 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.

From time to time, the Company may become party to legal actions arising 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.

As of September 30, 2008, the Company has remaining contractual commitments related to constructing its LNG liquefaction plant in California of $9.9 million.

Note 18 — 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 nine months ended September 30, 2007 and 2008.  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 September 30, 2008 are unchanged from December 31, 2007.

Income tax returns are subject to audit by federal, state and local governments, sometimes several years after a return is filed.  The Company is currently under audit by the Internal Revenue Service for tax years 2005 through 2007 and the State of California for tax years 2004 and 2005.  Disputes may arise during the course of such audits as to facts and different interpretations of tax law.

Note 19 — Recently Adopted Accounting Changes

On January 1, 2008, the Company adopted the applicable provisions of SFAS No. 157, Fair Value Measurements (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value and enhances disclosures about fair value measurements related to financial instruments. In December 2007, the FASB provided a one-year deferral of SFAS 157 for non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value on a recurring basis, at least annually. Accordingly, the Company’s adoption of SFAS 157 was limited to financial assets and liabilities.

During the nine months ended September 30, 2008, the Company’s financial instruments have consisted of short-term investments and natural gas futures contracts. The Company uses quoted market prices to measure fair value of its short-term investments.  The Company uses quoted forward price curves, discounted to reflect the time value of money, to value its natural gas futures contracts.  At September 30, 2008, the Company did not have any short-term investments and its futures contracts qualified for hedge accounting under SFAS No. 133 and are recorded in accumulated other comprehensive income in the accompanying condensed consolidated balance sheet.

SFAS 157 includes a fair value hierarchy that is intended to increase consistency and comparability in fair value measurements and related disclosures. The fair value hierarchy is based on inputs to valuation techniques that are used to measure fair value that are either observable or unobservable. Observable inputs reflect assumptions market participants would use in pricing an asset or liability based on market data obtained from independent sources while unobservable inputs reflect a reporting entity’s pricing based upon their own market assumptions. SFAS 157 establishes a three-tiered fair value hierarchy which prioritizes the inputs used in measuring fair value as follows:

·                  Level 1.  Observable inputs such as quoted prices in active markets;

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·                  Level 2.  Inputs, other than quoted prices, that are observable for the asset or liability, either directly or indirectly. These include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active; and

·                  Level 3.  Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.

The following table reflects the fair value as defined by SFAS 157, of the Company’s natural gas futures contracts:

Note 20 — Subsequent Events

Termination of FuelMaker Acquisition – On September 5, 2008, the Company entered into a Share Purchase Agreement with American Honda Motor Co., Inc. (“Honda”), John G. Armstrong (as sole trustee of The FuelMaker Trust) and FuelMaker Corporation, pursuant to which the Company agreed to purchase FuelMaker Corporation for $17 million in cash.  Under the terms of the purchase agreement, either the Company or Honda had the right to terminate the purchase agreement, without any obligation or liability thereunder, if the closing did not occur on or before October 3, 2008.

The closing did not occur by October 3, 2008 primarily due to the fact that the sellers (Honda and FuelMaker) were unable to deliver audited financial statements by October 3, 2008 for FuelMaker Corporation’s parent company, a subsidiary of Honda, which financial statements were required to be prepared in accordance with Canadian generally accepted accounting principles and reconciled to U.S. generally accepted accounting principles.  The Company continued negotiations with Honda after October 3, 2008 to extend the Share Purchase Agreement on revised terms.

On October 13, 2008, Honda delivered to the Company a notice that it intended to terminate the purchase agreement; and, after subsequent discussions, on October 15, 2008, the Company and Honda mutually agreed to terminate the purchase agreement in accordance with its terms.  The Company expects to record expenses of between $0.6 million and $0.8 million in the fourth quarter of 2008 for costs associated with the transaction.  There are no termination fees or other significant liabilities associated with the termination of the Share Purchase Agreement.

Issuance of Common Stock and Warrants – 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) one warrant to purchase up to 0.2571 shares of Common Stock (the “Series II Warrant”). 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. The Company received approximately $32.5 million after deducting the placement agents’ fees and other offering expenses.

The Series I Warrants are exercisable beginning six months from the date of issuance for a period of seven years from the date they become exercisable, and carry an exercise price of $13.50 per share. On the first anniversary of the issuance of the Series I warrants, the exercise price will reset to an exercise price equal to one-hundred twenty percent (120%) of the closing price of the Company’s common stock on such first anniversary date.  On the second anniversary of the issuance of the Series I warrants, the exercise price will reset to an exercise price equal to one-hundred twenty percent (120%) of the closing price of the Company’s common stock on such second anniversary date.  However, under the terms of the Series I warrants, no such reset adjustment will operate to increase the exercise price above the then current exercise price at the time of the first or second anniversary of the issuance of the Series I warrant.

The Series II Warrants became exercisable on November 5, 2008 upon the failure of the California Alternative Fuel Vehicles and Renewable Energy Act, or Proposition 10, in the California statewide election. The Series II Warrants have all been exercised on a cashless basis at the exercise price of $0.01 per share, which resulted in the issuance of 1,134,759 shares of common stock to the Series II Warrant holders on November 12, 2008.

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

The discussion in this section contains forward-looking statements. These statements relate to future events or our future financial performance. We have attempted to identify forward-looking statements by terminology such as “anticipate,” “believe,” “can,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “should,” “would” or “will” or the negative of these terms or other comparable terminology, but their absence does not mean that a statement is not forward-looking. These statements are only predictions and involve known and unknown risks, uncertainties and other factors, which could cause our actual results to differ from those projected in any forward-looking statements we make. See “Risk Factors” in Part II, Item 1A of this report for a discussion of some of these risks and uncertainties. This discussion should be read with our financial statements and related notes included elsewhere in this report.

We provide natural gas solutions for vehicle fleets primarily in the United States and Canada.  In April 2008, we opened our first CNG station in Lima, Peru, through our joint venture, Clean Energy del Peru.  Our primary business activity is selling CNG and LNG vehicle fuels 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 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 landfill gas at the McCommas Bluff landfill located 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 vast majority of our revenue from selling CNG and LNG to our customers. The balance of our revenue is provided by operating and maintaining natural gas fueling stations, designing and constructing natural gas fueling stations, financing our customers’ natural gas vehicle purchases and selling landfill gas through our interest in DCE.

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 sell the CNG or LNG, plus (iii) our proportionate share of the gasoline gallon equivalents sold through our joint venture in Peru and our interest in the McCommas Bluff Landfill in Dallas, Texas), and (2) our revenue and 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, 2005, 2006 and 2007 and for the three and nine months ended September 30, 2007 and 2008:

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Key trends in 2005, 2006, and 2007.  Vehicle fleet demand for natural gas fuels increased during the three years ended December 31, 2005, 2006 and 2007. We believe this growth in demand was attributable primarily to the rising prices of gasoline and diesel relative to CNG and LNG during these periods and increasingly stringent environmental regulations affecting vehicle fleets. 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 175 at September 30, 2008 (a 19.0% increase). The amount of CNG and LNG gasoline gallon equivalents we delivered from 2005 to 2007 increased by 32.6%. Our cost of sales also increased during these periods, which was attributable primarily to the increased price of natural gas and increased costs related to delivering CNG and LNG to our customers.

Recent developments. On September 5, 2008, we entered into a Share Purchase Agreement with American Honda Motor Co., Inc. (“Honda”), John G. Armstrong (as sole trustee of The FuelMaker Trust) and FuelMaker Corporation, pursuant to which we agreed to purchase FuelMaker Corporation for $17 million in cash.  Under the terms of the purchase agreement, either we or Honda had the right to terminate the purchase agreement, without any obligation or liability thereunder, if the closing did not occur on or before October 3, 2008.  On October 13, 2008, Honda delivered to us a notice that it intended to terminate the purchase agreement; and, after subsequent discussions, on October 15, 2008, we and Honda mutually agreed to terminate the purchase agreement in accordance with its terms.  On November 3, 2008, we completed a sale of 4,419,192 units of common stock and warrants for $7.92 per unit (See note 20 to the accompanying condensed consolidated financial statements for a discussion of the transaction) and raised net proceeds of approximately $32.5 million after deducting offering costs.

In October and November of 2008, we spent approximately $15 million supporting Proposition 10, the California Alternative Fuel Vehicles and Renewable Energy Initiative.  California voters failed to pass Proposition 10 in the November 4, 2008 election.  The $15 million we spent supporting Proposition 10 in October and November 2008 will be reflected in selling, general and administrative expense in our financial statements for the fourth quarter of 2008.

Anticipated future trends. We anticipate that, over the long term, the prices for gasoline and diesel will continue to be higher than the price of natural gas as a vehicle fuel, and more stringent emissions requirements will continue to make natural gas vehicles an attractive alternative to traditional gasoline and diesel powered vehicles. 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 a natural gas fueling station, 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 logistics of delivering more CNG and LNG to our customers, as well as from the anticipated expansion of our station network. We also continue to incur significant costs related to the LNG liquefaction plant we are in the process of building in California. 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.

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. 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 and received net proceeds of approximately $32.5 million.  (See note 20 to the accompanying condensed consolidated financial statements for a discussion of the transaction).  After this transaction, we had approximately $38.5 million in total cash and cash equivalents.

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Our business plan for the last three months of 2008 calls for approximately $23.0 million in capital expenditures (primarily related to building our LNG liquefaction plant in California and constructing new fueling stations) and $0.8 million for financing natural gas vehicle purchases by our customers.  We may also seek to acquire companies or assets in the natural gas fueling infrastructure, services and production industries.  If we do so, we may need to raise additional capital as necessary to fund any such acquisitions, which are not budgeted for in our 2008 business plan.  We anticipate that we will need to raise additional capital in 2009 to fund our 2009 capital expenditures program; however, the timing and necessity of any future capital raise will depend primarily on our rate of new station construction and other capital expenditures.

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. Gains and losses related to our futures activities, 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, 2005, 2006 and 2007, derivative (gains) losses were $(44,067,744), $78,994,947, and $0, respectively. For the nine months ended September 30, 2007 and 2008, derivative (gains) losses were $0 and $340,746, respectively. For this reason and others, we caution investors that our past operating results may not be indicative of future results. For more information, please read “Volatility of Earnings and Cash Flows” and “Risk Management Activities” below.

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

Operations

We generate revenues principally by selling CNG and LNG to our vehicle fleet customers. For the nine months ended September 30, 2008, CNG represented 66% and LNG represented 34% of our natural gas sales (on a gasoline gallon equivalent basis). To a lesser extent, we generate revenues by operating and maintaining natural gas fueling stations that are owned either by us or our customers and selling landfill gas provided by our interest in DCE (commencing in August 2008). 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. In addition, we generate a small portion of our revenues by designing and constructing fueling stations and selling or leasing those stations to our customers. 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. 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 no longer intend to offer 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 revised natural gas hedging policy revised in May 2008.  Our fleet customers typically are billed monthly based on the volume of CNG sold at a station. The remainder of our CNG sales are on a per fill-up basis at prices we set at the pump based on prevailing market conditions. These customers typically pay using a credit card at the station.  In April 2008, we opened our first CNG station in Lima, Peru through our joint venture Clean Energy del Peru.

LNG Sales

We sell substantially all of our LNG to fleet customers, who typically own and operate their fueling stations. We also sell a small volume of LNG to customers for non-vehicle use. We procure LNG from third-party producers and also produce LNG at our liquefaction plant in Texas. 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 60 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. 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 no longer intend to offer price-cap contracts to our customers, but we will continue to perform our obligations under price-cap contracts we

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entered into before January 1, 2007, including two one-year renewal periods beginning April 1, 2009 that one of our customers is entitled to should they choose to exercise such renewals.  The renewal periods, if exercised, would obligate us to sell the customer approximately 2.1 million LNG gallons on an annual basis subject to a price cap of $7.50 per MMbtu on the SoCal Border index for each renewal year.  We will continue to offer fixed price contracts as appropriate and consistent with our revised 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 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. These new excise tax rates are approximately the same as those for gasoline and diesel fuel.

Operation and Maintenance

We generate a smaller 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.

Station Construction

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

Vehicle Acquisition and Finance

In 2006, we commenced offering vehicle finance services for some of our customers’ purchases of natural gas vehicles or the conversion of their existing gasoline or diesel powered vehicles to operate on natural gas. We loan to our customers 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 September 30, 2008, 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.  DCE owns a facility that collects, processes and sells landfill gas at the McCommas Bluff landfill located in Dallas, Texas.  A small portion of our revenues are derived from our interest in DCE.

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. See “Critical Accounting Policies” below. We have therefore recorded any changes in the fair market value of these contracts 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 $33.1 million and $5.7 million for the three months ended September 30, 2005 and June 30, 2008, and derivative losses of $19.9 million, $0.3 million, $65.0 million, $13.7 million and $6.0 million for the three months ended December 31, 2005, March 31, 2006, September 30, 2006, December 31, 2006 and September 30, 2008,

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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 and March 31, 2008.

For the three months ended June 30, 2008, we recognized a $5.7 million derivative gain with respect to futures contracts purchased to hedge our exposure to a fixed price contract for which we bid, and we recognized a $6.0 million derivative loss during the three months ending September 30, 2008 with respect to the sale of certain of these contracts (see note 6 to the accompanying condensed consolidated financial statements). Commencing with the adoption of our revised natural gas hedging policy in February 2007 (as revised in May 2008), we plan to structure all subsequent futures contracts as cash flow hedges under SFAS 133, but we cannot be certain that they will qualify. See “Risk Management Activities” below. If the futures contracts do not qualify for hedge accounting, we could incur significant increases or decreases in our earnings based on fluctuations in the market value of these 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 September 30, 2008, we had $0.8 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.

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, 2007 and our current report on Form 8-K dated June 19, 2008, which discussion is incorporated herein by reference.

On April 18, 2008, we purchased certain natural gas futures contracts to attempt to economically hedge our exposure to cash flow variability related to the commodity component of an LNG supply contract for which we had submitted a fixed-price bid. As previously disclosed in our Form 8-K dated June 19, 2008, the supply contract for which the futures contracts were purchased was awarded to our competitor. We protested the award of the contract to our competitor and ultimately we were awarded a portion of the contract representing approximately one-third of the contract volumes. Ultimately, we realized a net loss of $0.3 million related to the sale of the futures contracts purchased with respect to the portion of the fixed-price contract that we were not awarded. The remaining futures contracts currently qualify for hedge accounting as cash flow hedges under SFAS 133.

Critical Accounting Policies

For the period covered by this report, there have been no material changes to the critical accounting policies we use and have explained in our annual report on Form 10-K for the fiscal year ended December 31, 2007.

Recently Issued Accounting Pronouncements

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS 157 does not require any new fair value measurements. In February 2008, the FASB amended SFAS 157 to exclude SFAS 13, “Accounting for Leases.” In addition, the FASB delayed the effective date of SFAS 157 for non-financial assets and liabilities to fiscal years beginning after November 15, 2008. We adopted the provisions of SFAS 157 related to our financial assets and liabilities on January 1, 2008, which did not have a material impact on our financial statements. In accordance with the new standard, we have provided additional disclosures which are included in the notes to our condensed consolidated financial statements.  With respect to our non-financial assets and liabilities, we are currently evaluating the impact, if any, SFAS 157 may have on our financial statements.

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In February 2007, the FASB issued Statement of Financial Accounting Standard No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”). SFAS 159 permits entities to choose to measure certain financial instruments and other eligible items at fair value when the items are not otherwise currently required to be measured at fair value. Under SFAS 159, the decision to measure items at fair value is made at specified election dates on an irrevocable instrument-by-instrument basis. Entities electing the fair value option would be required to recognize changes in fair value in earnings and to expense upfront costs and fees associated with the item for which the fair value option is elected. Entities electing the fair value option are required to distinguish, on the face of the statement of financial position, the fair value of assets and liabilities for which the fair value option has been elected and similar assets and liabilities measured using another measurement attribute. Unrealized gains and losses arising subsequent to adoption are reported in earnings. We adopted this statement as of January 1, 2008 and elected not to apply the fair value option to any of our financial instruments.

In December 2007, the FASB finalized the provisions of the Emerging Issues Task Force (“EITF”) issue No. 07-1, Accounting for Collaborative Arrangements (“EITF 07-1”). EITF 07-1 provides guidance and required financial statement disclosures for collaborative arrangement. EITF 07-01 is effective for financial statements issued for fiscal years beginning after December 15, 2008. We are currently evaluating the impact, if any, EITF 07-1 may have on our financial statements.

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 in the first fiscal year beginning on or after December 15, 2008.

In December 2007, the FASB issued Statement of Financial Accounting Standard No. 160, Minority Interests in Consolidated Financial Statements—an amendment of ARB No. 51 (“SFAS 160”). SFAS 160 provides new accounting guidance and disclosure and presentation requirements for non-controlling interests in a subsidiary. SFAS 160 is effective for the first fiscal year beginning on or after December 15, 2008. We are currently evaluating the impact, if any, SFAS 160 may have on our financial statements.

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” an amendment of SFAS 133 (“SFAS 161”). SFAS 161 requires disclosures of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for fiscal years beginning after November 15, 2008, with early adoption permitted. We are currently evaluating the impact, if any, SFAS 161 may have on our financial statements.

In April 2008, the FASB Staff Position (“FSP”) issued SFAS No. 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP SFAS 142-3”). FSP SFAS 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 SFAS No. 142, “Goodwill and Other Intangible Assets.” The intent of FSP SFAS 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141 (revised 2007), “Business Combinations,” and other U.S. generally accepted accounting principles (“GAAP”). FSP SFAS 142-3 is effective for fiscal years beginning after December 15, 2008 and we will adopt the pronouncement in the first quarter of fiscal year 2009. We are currently evaluating the effect that the adoption of FSP SFAS 142-3 will have on our results of operation and financial position or cash flows, if any, but do not expect it will have a material impact.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Principles” (“SFAS 162”). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (the GAAP hierarchy). SFAS 162 will become effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” We do not expect the adoption of SFAS 162 will have a material impact on our results of operations and financial condition.

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Results of Operations

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

Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

 Revenue.   Revenue increased by $6.1 million to $35.3 million in the three months ended September 30, 2008, from $29.2 million in the three months ended September 30, 2007. This increase was primarily the result of an increase in our average price per gallon between periods. Our effective price per gallon was $1.57 in the three months ended September 30, 2008, which represents a $0.35 per gallon increase from $1.22 in the three months ended September 30, 2007. Revenue also increased between periods as we recorded $5.6 million of revenue related to fuel tax credits in the third quarter of 2008, compared to $4.6 million in the third quarter of 2007.  We also experienced a $0.1 million increase in station construction revenues between periods.  These increases were offset by the decrease in the number of gallons delivered between periods from 20.0 million gasoline gallon equivalents to 18.7 million gasoline gallon equivalents. The decrease in volume was primarily related to the loss of a portion of the new City of Phoenix LNG supply contract that began July 1, 2008.

Cost of sales.   Cost of sales increased by $5.8 million to $26.1 million in the three months ended September 30, 2008, from $20.3 million in the three months ended September 30, 2007. Our cost of sales primarily increased between periods as our effective cost per gallon rose to $1.39 in the three months ended September 30, 2008, which represents a $0.38 per gallon increase over the three months ended September 30, 2007.  Also contributing to the increase in cost of sales was an increase in station construction cost of $0.2 million between periods.  Offsetting these increases was a $1.8 million decrease in costs related to delivering less CNG and LNG between periods.

Derivative (gains) losses.   Derivative losses increased to $6.0 million in the three months ended September 30, 2008, from $0.0 million in the three months ended September 30, 2007. This increase was due to a loss we recognized in the three month period ended September 30, 2008 with respect to the sale of certain futures contracts we purchased in conjunction with the portion of a fixed-price bid on a LNG supply contract that we were not awarded (see note 6 to the accompanying condensed consolidated financial statements). We did not sell or own any futures contracts during the three months ended September 30, 2007.

Selling, general and administrative.   Selling, general and administrative expenses increased by $1.9 million to $11.4 million in the three months ended September 30, 2008, from $9.5 million in the three months ended September 30, 2007.  Our stock option expense accounted for $1.1 million of the increase between periods primarily due to options issued in 2008 for new employees.  Our marketing expenses also increased $0.9 million between periods due to certain advertising we conducted at the Ports of Los Angeles and Long Beach and costs we incurred to support Proposition 10.

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Depreciation and amortization.   Depreciation and amortization increased by $0.5 million to $2.3 million in the three months ended September 30, 2008, from $1.8 million in the three months ended September 30, 2007. This increase was primarily related to the result of additional amortization expense in the three months ended September 30, 2008 related to the amortization of the identifiable intangible asset recorded in connection with the acquisition of our 70% interest in DCE in August 2008 and our increased property and equipment balances between periods, primarily related to our expanded station network.

Interest income, net.   Interest income, net, decreased by $1.3 million from $1.4 million in the three months ended September 30, 2007, to $0.1 million for the three months ended September 30, 2008. This decrease was primarily the result of a decrease in interest income in the three months ended September 30, 2008 due to lower average cash balances on hand during the three months ended September 30, 2008 as compared to the third quarter of 2007.  We also incurred interest expense in the third quarter of 2008 related to the debt we incurred to acquire our interest in DCE in August 2008.

Other income (expense), net.   There was no significant change in other income (expense), net, between the three months ended September 30, 2007 and the three months ended September 30, 2008.

Equity in gains (losses) of equity method investee.  During the three months ended September 30, 2008, we recognized $20,000 of equity gains related to our joint venture in Peru. The CNG station owned by the joint venture opened in April 2008.

Minority interest in net income.  During the three months ended September 30, 2008, we recorded $14,000 for the minority interest in the net income of DCE.  The minority 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.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Revenue.   Revenue increased by $11.8 million to $99.8 million in the nine months ended September 30, 2008, from $88.0 million in the nine months ended September 30, 2007. This increase was primarily the result of an increase in our average price per gallon between periods. Our effective price per gallon was $1.52 in the nine months ended September 30, 2008, which represents a $0.27 per gallon increase from $1.25 in the nine months ended September 30, 2007. Revenue also increased between periods as we recorded $15.5 million of revenue related to fuel tax credits in the first nine months of 2008 compared to $12.8 million in the first nine months of 2007. These increases were offset by the decrease in the number of gallons delivered between periods from 57.1 million gasoline gallon equivalents to 54.8 million gasoline gallon equivalents. The loss of a portion of the City of Phoenix LNG supply contract after June 30, 2008, the loss of an LNG O&M contract related to a facility that was relocated, and the loss of a CNG supply contract with a customer who decided to procure their own natural gas supply together accounted for 4.7 million gasoline gallon equivalents of the decrease.  These decreases were offset by the addition of 1.6 million gasoline gallon equivalents due to the addition of new customers (OCTA, Santa Cruz Metropolitan Transit Authority, City of Los Angeles, Southland Transit, Regional Transit Commission of Nevada, and Regional Transit Authority of Ohio), 0.2 million gasoline gallon equivalents related to our interest in our joint venture in Peru, and 0.6 million gasoline gallon equivalents from our 70% interest in DCE. We also experienced a $2.7 million decrease in station construction revenues between periods.

Cost of sales.   Cost of sales increased by $13.0 million to $77.1 million in the nine months ended September 30, 2008, from $64.1 million in the nine months ended September 30, 2007. Our cost of sales increased between periods as our effective cost per gallon rose to $1.40 in the nine months ended September 30, 2008, which represents a $0.33 per gallon increase over the nine months ended September 30, 2007. Offsetting the increase in our effective cost per gallon was the decrease in station construction costs of $2.4 million between periods and a $3.3 million decrease in costs related to delivering less CNG and LNG between periods.

Derivative (gains) losses.   Derivative losses increased to $0.3 million in the nine months ended September 30, 2008, from $0.0 million in the nine months ended September 30, 2007. This increase was due to a loss we recognized in the nine month period ended September 30, 2008 on futures contracts we purchased in April 2008 in conjunction with a fixed-price bid on a LNG supply contract we had submitted (see note 6 to the accompanying condensed consolidated financial statements) and sold in July 2008. We did not sell or own any futures contracts during the nine months ended September 30, 2007.

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Selling, general and administrative.   Selling, general and administrative expenses increased by $8.8 million to $35.1 million in the nine months ended September 30, 2008, from $26.3 million in the nine months ended September 30, 2007. A significant portion of this increase related to a $4.2 million increase in our marketing expenses due to certain advertising we conducted related to the Ports of Los Angeles and Long Beach and costs we incurred to support Proposition 10.  Stock option expense between periods increased $2.4 million due to options issued in 2008 for new employees. There was also an increase of $0.7 million in salaries and benefits between periods primarily related to the hiring of additional employees. Our headcount increased from 118 at September 30, 2007 to 134 at September 30, 2008. Our professional service fees increased $0.8 million between periods, primarily for legal, audit and consulting services related to our obligations as a public company.  Our business insurance costs increased $0.5 million between periods primarily due to an increase in premiums related to our directors’ and officers’ insurance between periods.

Depreciation and amortization.   Depreciation and amortization increased by $1.5 million to $6.6 million in the nine months ended September 30, 2008, from $5.1 million in the nine months ended September 30, 2007. This increase was due to additional depreciation expense in the nine months ended September 30, 2008 related to increased property and equipment balances between periods, primarily related to our expanded station network, and due to the amortization of the identifiable intangible asset recorded in connection with the acquisition of our 70% interest in DCE, in August 2008.

Interest income, net.   Interest income, net, decreased by $1.1 million from $2.3 million in the nine months ended September 30, 2007, to $1.2 million for the nine months ended September 30, 2008. This decrease was primarily the result of a decrease in interest income in the nine months ended September 30, 2008 due to lower average cash balances on hand between periods.

Other income (expense), net.   Other income (expense), net, was $11,000 of income in the nine months ended September 30, 2008, as compared to $229,000 of expense in the nine months ended September 30, 2007. The increase was primarily related to the write-off of certain costs related to station relocation in the nine months ended September 30, 2007 that did not occur in the nine months ended September 30, 2008, and the sale of certain assets in the nine months ended September 30, 2008 that did not occur in the nine months ended September 30, 2007.

Equity in gains (losses) of equity method investee.  During the nine months ended September 30, 2008, we recognized $120,000 of equity losses related to our joint venture in Peru. The CNG station owned by the joint venture opened in April 2008.

Minority interest in net income.  During the nine months ended September 30, 2008, we recorded $14,000 for the minority interest in the net income of DCE.  The minority 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 borrowed $18.0 million under a term loan and an additional $4.2 million (as of September 30, 2008) under a line of credit (see note 11 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 (See note 20 to the accompanying condensed consolidated financial statements for a discussion of the transaction) 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,

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our support for Proposition 10 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 nine months of 2008 primarily through cash on hand.

At September 30, 2008, we had total cash and cash equivalents of $30.4 million compared to $67.9 million at December 31, 2007.  Following the sale of 4,419,192 units of common stock and warrants, (consisting of an aggregate of 4,419,492 shares of common stock, Series I Warrants to purchase up to an aggregate of 3,314,394 shares of common stock, and Series II Warrants to purchase up to an aggregate of 1,136,364 shares of common stock) in a transaction that closed November 3, 2008, we had total cash and cash equivalents of approximately $38.5 million.  We did not have any short-term investments at September 30, 2008 as we sold them all during the nine month periods ended September 30, 2008.  We had $12.5 million of short-term investments at December 31, 2007.

Cash provided by operating activities was $7.8 million for the nine months ended September 30, 2008, compared to cash provided by operating activities of $8.6 million for the nine months ended September 30, 2007.   The decrease in operating cash flow resulted primarily from an increase in our net loss between periods.  Offsetting this decrease was a $13.3 million increase between periods related to net returns of LNG truck deposits.  The remaining changes primarily resulted from changes in working capital balances, which were mostly due to timing differences related to the various cash flows between periods.

Cash used in investing activities was $72.7 million for the nine months ended September 30, 2008, compared to $45.1 million for the nine months ended September 30, 2007. Our purchases of property and equipment were $59.8 million during the first nine months of 2008.  Included in purchases of property and equipment in the first nine months of 2008 was $39.9 million of construction costs related to our LNG liquefaction plant in California.  In the first nine months of 2007, we purchased $14.8 million of short-term investments with our initial public offering proceeds from May 2007. In the first nine months of 2008, all of our short-term investments were sold or matured resulting in net cash proceeds of $12.5 million.  In August 2008, we purchased a 70% interest in DCE and our total cash outlay for the acquisition including transaction costs was $19.6 million.  We also made an investment during the first nine months of 2008 of $3.2 million in the Vehicle Production Group, LLC, a company developing a CNG taxi and a paratransit vehicle, and transferred $2.5 million of our cash balance to a restricted account in accordance with our August 2008 credit agreement with PlainsCapital Bank.

Cash provided by financing activities for the nine months ended September 30, 2008 was $27.3 million, compared to $110.3 million for the nine months ended September 30, 2007.  In May 2007, we completed our initial public offering, which raised $110.3 million during the nine month period ended September 30, 2007.  In August 2008, we borrowed $22.1 million to fund the acquisition of our interest in DCE, and to pay other amounts related to the transaction.  In addition, in September 2008, we issued and sold 319,488 shares of our common stock for an aggregate purchase price of approximately $5.0 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, and our capital expenditure requirements, which consist primarily of station construction, LNG plant construction, and the purchase of LNG tanker trailers and equipment.

We intend to fund our principal liquidity requirements through cash and cash equivalents, cash provided by operations and through debt or equity financings. We anticipate we have enough cash to fund our 2008 capital expenditure budget. We anticipate that we will need to raise additional capital in 2009 to fund our 2009 capital expenditure budget in full; however, the timing and necessity of any future capital raise will depend primarily on the rate of new station construction and other capital expenditures. We may also seek to acquire companies or assets in the natural gas fueling infrastructure, services and production industries.  If we do so, we may need to raise additional capital as necessary to fund any such acquisitions as we did not contemplate any acquisitions in our 2008 capital expenditure plan.

Capital Expenditures

We expect to make capital expenditures, net of grant proceeds, of approximately $80.7 million in 2008 to construct new natural gas fueling stations, to complete construction of our LNG liquefaction plant in California, and for general corporate purposes. Of the $80.7 million, we have budgeted approximately $49.9 million during 2008 to complete construction of our LNG liquefaction plant in California, which we anticipate will be operational in November 2008. We also anticipate using approximately $3.4 million to finance the purchase of natural gas vehicles by our customers during 2008.

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Contractual Obligations

The following represents the scheduled maturities of our contractual obligations as of September 30, 2008: