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, 2007

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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” 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 1, 2007, there were 44,214,095 shares of the registrant’s common stock, par value $0.0001 per share, issued and outstanding.

CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES
INDEX

Table of Contents

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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, 2006 and September 30, 2007 (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 and Nine Months Ended
September 30, 2006 and 2007
(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, 2006 and 2007
(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 providing natural gas fueling solutions to its customers 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 over 170 fueling locations principally in California, Texas, Colorado, Maryland, New York, New Mexico, Washington, Massachusetts, Georgia, and Arizona within the United States, and in British Columbia and Ontario within Canada.

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, 2006 and 2007. All intercompany accounts and transactions have been eliminated in consolidation. The three and nine month periods ended September 30, 2006 and 2007 are not necessarily indicative of the results to be expected for the year ending December 31, 2007 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, 2006 that are included in the Company’s Form S-1 filed with the SEC.

Note 2 — 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 3 — 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 six 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.

Note 4 — Derivative Financial Instruments

The Company, in an effort to manage its natural gas commodity price risk exposures, utilizes derivative financial instruments. The Company often 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 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. The Company’s derivative instruments did not qualify for hedge accounting under SFAS  133 for the year ended December 31, 2006. As such, changes in the fair value of the derivatives were recorded directly to the consolidated statements of operations during the year. The Company did not have any futures contracts outstanding during the three or nine month periods ended September 30, 2007.

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 accompanying condensed consolidated statements of operations. For the nine month periods ended September 30, 2006 and 2007, the Company’s unrealized net loss amount totaled $73,955,837 and $0, respectively.

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The Company is required to make certain deposits on its futures contracts, should any exist. At December 31, 2006 and September 30, 2007, the Company did not have any deposits outstanding as it did not have any futures contracts outstanding at the end of these periods.

During the nine months ended September 30, 2006 and 2007, the Company recognized realized gains of $8,674,251 and $0, respectively, related to the sales of futures contracts.

Note 5 — Fixed Price and Price Cap Sales Contracts

The Company has entered into contracts with various customers, primarily municipalities, to sell liquefied natural gas (LNG) or compressed natural gas (CNG) at fixed prices or at prices subject to a price cap. As of January 1, 2007, the Company no longer intends to enter into price cap contracts. 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 4) 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).

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, 2007:

(a)           Estimated volumes are in gasoline gallon equivalents for CNG contracts and are in LNG gallons for LNG contracts and represent the volumes the Company anticipates 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 embedded in the customer’s contract.

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At September 30, 2007, based on natural gas futures prices as of that date, the Company estimates it will incur between $5.0 million and $6.2 million to cover the increased price of natural gas above the inherent price of natural gas embedded in its 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, 2007, and these estimates may change based on future natural gas prices and may be significantly higher or lower. The Company’s volumes under these contracts, in gasoline gallon equivalents, expire as follows:

Note 6 —Other Receivables

Other receivables at December 31, 2006 and September 30, 2007 consisted of the following:

Note 7 — Land, Property and Equipment

Land, property and equipment, at cost, at December 31, 2006 and September 30, 2007 are summarized as follows:

Note 8 — Accrued Liabilities

Accrued liabilities at December 31, 2006 and September 30, 2007 consisted of the following:

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Note 9 — 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, 2006 and 2007, respectively, as the inclusion of the securities would be anti-dilutive to the calculation. The amounts outstanding as of September 30, 2006 and 2007 for these instruments are as follows:

Note 10 — Comprehensive Income

The following table presents the Company’s comprehensive income for the nine months ended September 30, 2006 and 2007:

Note 11 — Stock Based Compensation

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

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Stock Options

The following table summarizes all stock option activity during the nine months ended September 30, 2007:

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 2007:

The weighted average grant date fair value of options granted using these assumptions was $6.81 for the nine months ended September 30, 2007.

Note 12 — Use of Estimates

The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles require management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and revenues and expenses during the reporting period. Actual results could differ from those estimates.

Note 13 — 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, 2007, the Company had entered into purchase commitments totaling $33.0 million related to constructing its LNG liquefaction plant in California, of which $16.8 million had been paid as of this date.

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Note 14 — Income Taxes

In June 2006, the FASB issued FASB Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.” This interpretation specifies that benefits from tax positions should be recognized in the financial statements only when it is more-likely-than-not that the tax position will be sustained upon examination by the appropriate taxing authority having full knowledge of all relevant information. A tax position meeting the more-likely-than-not recognition threshold should be measured at the largest amount of benefit for which the likelihood of realization upon ultimate settlement exceeds 50 percent.

The Company adopted the provisions of FIN 48 on January 1, 2007. On December 31, 2006 and September 30, 2007, the Company’s liabilities for uncertain tax positions were not significant.

The Company’s policy is to recognize interest and penalties related to liabilities for uncertain tax benefits in the provisions for income and other taxes on the consolidated condensed statements of income. The net interest and penalties incurred were immaterial for the three and nine months ended September 30, 2006 and 2007.

The Company is subject to audit by tax authorities for varying periods in various tax jurisdictions. Taxable years from 2002 and 2003, respectively, are subject to audit for state and U.S. federal corporate income tax purposes. The Company is currently under audit by the State of California for tax years 2004 and 2005. Disputes may arise during the course of such audits as to facts and matters of law.

During June 2007, the Company requested permission from the Internal Revenue Service to change its method of accounting for its derivative gains and losses related to futures contracts that are sold in one period but relate to a subsequent period. On July 5, 2007, the Internal Revenue Service granted the Company’s request. The Company began reporting the income tax impact of the change in the third quarter of 2007. The Company anticipates that the adoption of the new method will create a federal and state alternative minimum tax liability in the amount of $825,000 for 2007, which liability will generate a corresponding alternative minimum tax credit in the same amount which can be carried forward indefinitely to offset future regular income tax liability in excess of the tentative minimum tax.

Note 15 — Subsequent Event

On October 17, 2007, the Company entered into an LNG sales agreement with Spectrum Energy Services, LLC (SES), to purchase, on a take-or-pay basis over a term of 10 years, 45,000 gallons per day of LNG from a plant to be constructed by SES in Ehrenberg, Arizona, which is near the California border.

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. 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 in the United States and Canada. Our primary business activity is supplying 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.

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 supplying 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, and financing our customers’ natural gas vehicle purchases.

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Key operating data. In evaluating our operating performance, our management focuses primarily on (1) the amount of CNG and LNG gasoline gallon equivalents delivered and (2) our revenue and net income (loss). The following table, which you should read in conjunction with our financial statements and notes contained elsewhere in this report, presents our key operating data for the years ended December 31, 2004, 2005 and 2006 and for the three and nine months ended September 30, 2006 and 2007:

Key trends in 2004, 2005, 2006 and the first nine months of 2007. Vehicle fleet demand for natural gas fuels increased significantly from January 1, 2004 through the first nine months of 2007. 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. Sales to previously existing customers also increased during these periods as they expanded their fleets.

The annual amount of CNG and LNG gasoline gallon equivalents we delivered increased by 48% from 2004 to 2006. The amount of CNG and LNG gasoline gallon equivalents we delivered from the first nine months of 2006 to the first nine months of 2007 increased by 13%. The increase in gasoline gallon equivalents delivered, together with generally 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 increased costs related to delivering more CNG and LNG to our customers and the increased price of natural gas.

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 traditional gasoline and diesel powered vehicles more expensive for vehicle fleets. We believe there will be significant growth in the consumption of natural gas as a vehicle fuel generally, and our goal is to capitalize on this trend and enhance our leadership position as this market expands. We recently began focusing on the seaports market. We are in the process of building a natural gas fueling station, and plan to build additional natural gas fueling stations that service 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 airport markets. Consistent with the anticipated growth of our business, we also expect that our operating costs 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 plan to incur significant costs related to the LNG liquefaction plant we are in the initial stages of building in California. Additionally, we intend to increase our sales and marketing team 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. In 2007, we expect to spend our cash primarily on building an LNG liquefaction plant in California, constructing new fueling stations, purchasing new LNG tanker trailers, financing natural gas vehicle purchases by our customers and for 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. For more information, see “Liquidity and Capital Resources” below.

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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 consolidated financial statements, have materially impacted our results of operations in recent periods. For the years ended December 31, 2004, 2005 and 2006 derivative (gains) losses were $(10,572,349), $(44,067,744), and $78,994,947, respectively. For the nine month periods ended September 30, 2006 and 2007, derivative losses were $65,281,586 and $0, respectively. For this reason and others, we caution investors that our past operating results may not be indicative of future results. For more information, see “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, 2007, CNG represented 63% and LNG represented 37% 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. 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 also 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. 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. Our fleet customers typically are billed monthly based on the volume of CNG sold at a station. A smaller portion of our CNG sales are on a per fill-up basis at prices we set at the pump based on prevailing market conditions. These customers typically pay using a credit card at the station.

LNG Sales

We sell substantially all of our LNG to fleet customers, who typically own and operate their fueling stations. We also sell 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 before December 31, 2006. 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. Our LNG contracts provide that we charge our customers periodically based on the volume of LNG supplied.

Government Incentives

From October 1, 2006 through September 30, 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.

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The Internal Revenue Service has not issued final guidance concerning VETC as it relates to LNG sales to tax-exempt entities. Consequently, we have not recorded any benefit of VETC related to these sales in our consolidated financial statements for contracts entered into prior to October 1, 2006.

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. Through these services, 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 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. For the nine month period ended September 30, 2007, we generated $0.2 million of revenue from vehicle finance activities.

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 our futures contracts to date have not qualified for hedge accounting under SFAS  133. See “Critical Accounting Policies—Derivative Activities” 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 for the three months ended September 30, 2005 and experienced derivative losses of $19.9 million, $0.3 million, $65.0 million and $13.7 million for the three months ended December 31, 2005, March 31, 2006, September 30, 2006 and December 31, 2006, respectively. We had no derivative gains or losses for the three months ended June 30, 2006, March 31, 2007, June 30, 2007 and September 30, 2007. Commencing with the adoption of our revised natural gas hedging policy in February 2007, 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.

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. At September 30, 2007, we had no futures contracts outstanding and no amounts on deposit.

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Risk Management Activities

A significant portion of our natural gas fuel sales are covered by contracts to sell LNG or CNG to our customers at a fixed price or a variable index-based price subject to a cap. These contracts expose us to the risk that the price of natural gas may increase above the natural gas cost component included in the price at which we are committed to sell gas to our customers. We account for sales of natural gas under these contracts as described below in “Critical Accounting Policies—Fixed Price and Price Cap Sales Contracts.”

Risk Management Practices Before February 2007

Historically, when we entered into a contract to sell natural gas fuel to a customer at a fixed price or a variable price subject to a cap, we generally sought to manage our exposure to natural gas price increases for some or all of the expected contract volumes in the natural gas futures market. We did this by purchasing futures contracts that were designed to cover the difference between the commodity portion of the price at which we were committed to sell natural gas and the price we had to pay for gas at delivery, thereby fixing the cost of natural gas we were paying. We generally purchased futures contracts covering all or a portion of our anticipated volumes in future periods.

From time to time, if we believed natural gas prices would decline in the future, we periodically elected to terminate futures contracts associated with fixed price or price cap customer contracts by selling the futures contracts and recognizing a gain upon such sales. When we did so, we lost future economic protections provided by the futures contracts.

From 2003 through 2005, we sold futures contracts covering estimated sales volumes over future periods and realized a net gain of approximately $44.8 million upon the sale of these contracts. In 2006, we disposed of certain futures contracts covering estimated sales volumes over future periods and realized a net loss of $78.7 million.

Our derivative activities are reflected in the line item derivative (gains) losses in our consolidated statements of operations. Two components make up this line item: (1) realized (gains) losses, and (2) unrealized (gains) losses. Realized (gains) losses represent the actual (gains) losses we realize when we sell or settle a futures contract during a period. Unrealized (gains) losses represent the (gain) or loss we record at the end of each period when we mark to market our open futures contracts at the end of each period. For realized (gains) losses on contracts sold or settled during a period, there is typically a corresponding unrealized loss (gain) on the contracts since the contracts are no longer outstanding at the end of the period and are therefore marked to zero.

We have a derivative committee of our board of directors and have historically conducted our futures contract activity under the advice of BP Capital L.P. (BP Capital), an entity of which Boone Pickens, our largest stockholder and a director, is the principal. Through December 31, 2006, we paid BP Capital a monthly fee of $10,000 and a commission equal to 20% of our realized gains, net of realized losses, during a calendar year relating to the purchase and sale of natural gas futures contracts. BP Capital remitted realized net gains to us, less its applicable commissions, on a monthly basis. We paid fees to BP Capital of $0.4 million in 2004, $11.7 million in 2005, $2.4 million in 2006, and $0 during the first three months of 2007. In March 2007, we amended our agreement with BP Capital to remove the 20% commission on our realized net gains during a calendar year.

We historically have purchased our natural gas futures contracts from Sempra Energy Trading Corp (Sempra). The futures are based on the Henry Hub natural gas price set on the New York Mercantile Exchange. One futures contract for CNG covers approximately 80,000 gasoline gallon equivalents of CNG, and one futures contract for LNG covers approximately 120,000 gallons of LNG. Each contract had historically required a deposit from us of $1,000, which is below market due to the fact that Boone Pickens had guaranteed our futures obligations to Sempra. Without this guarantee, which was cancelled March 7, 2007, we estimate the deposit amount rate will be approximately $5,000 to $12,000 per contract depending on market conditions. Additionally, without this guaranty, Sempra may terminate our contract. As of September 30, 2007, we had no futures contracts outstanding and no amounts on deposit.

August 2006 Purchase of Futures Contracts and December 2006 Assumption by Boone Pickens

On August 2, 2006, we purchased the following futures contracts and made related deposits of $9.5 million:

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In December 2006, Mr. Pickens assumed all of these futures contracts, together with any and all associated liabilities and obligations, in exchange for (1) the issuance to Mr. Pickens of a five-year warrant to purchase up to 15,000,000 shares of our common stock at a purchase price of $10.00 per share (which warrant was valued at $80.9 million), and (2) the assignment to Mr. Pickens of any refunds of margin deposits related to the assumed futures contracts that were made using money borrowed under the line of credit with Mr. Pickens. At the time of assumption, these futures contracts had lost $78.7 million in value. The difference between the value of the warrant and the value of the losses on the futures contracts ($2.2 million) was recorded in our statement of operations as a loss on extinguishment of derivative liability. This warrant will be dilutive to net income per share if the fair market value of our common stock exceeds $10 per share in the future.

Adoption of Revised Natural Gas Hedging Policy in February 2007

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 which 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 offer of fixed-price sales contracts pursuant to the policy as follows:

1.             We may purchase futures contracts only to hedge our exposure to variability in expected future cash flows (such variability to be referred to hereafter as Cash Flow Variability) related to fixed-price sales contracts.

2.             We will purchase futures contracts in quantities reasonably expected to hedge effectively our exposure to Cash Flow Variability related to each fixed-price sales contract that we enter into after the date of the policy.

3.             We may offer a fixed-price sales contract to a customer only if the following three conditions are met:

a.             We purchase futures contracts in quantities reasonably expected to hedge effectively our exposure to Cash Flow Variability related to the fixed-price sales contract;

b.             We reasonably expect we will have funds sufficient: (i) to make the initial margin deposit(s) related to the intended futures contracts; and (ii) to cover estimated margin calls related to these futures contracts; and

c.             For any contract covering 2.5 million or more gasoline gallon equivalents of CNG or LNG per year (or any contract that, combined with previous contracts that year, would cause the total gasoline gallon equivalents contracted for to exceed 7.5 million gasoline gallon equivalents that year), we consult with the derivative committee regarding the proposed transaction, and the derivative committee approves both the offer of the fixed-price sales contract(s) and the purchase of the associated futures contracts.

4.             When we enter into a fixed-price sales contract according to paragraph 3 above, we will purchase sufficient futures contracts to hedge our estimated exposure to the basis differential between: (a) the price of natural gas at the NYMEX Henry Hub delivery point, and (b) the price of natural gas at the customer’s delivery point.

5.             If, during the duration of a fixed-price sales contract (including, without limitation, a contract signed before the adoption of this policy, a contract entered into after the adoption of this policy where futures contracts were not originally purchased to hedge the contract, and a contract that subsequently experiences a significant increase in volume that was not originally contemplated when the original futures contracts were purchased to hedge the contract), we do not have associated futures contracts in place that are sufficient to hedge effectively our estimated exposure to Cash Flow Variability related to that fixed-price sales contract, we may purchase futures contracts in quantities reasonably expected to hedge effectively our exposure to Cash Flow Variability related to that fixed-price sales contract, but only if the following two conditions are met:

a.             We reasonably expect we will have funds sufficient: (i) to make the initial margin deposit(s) related to the intended futures contracts; and (ii) to cover estimated margin calls related to these futures contracts; and

b.             For any fixed-price sales contract covering 1.5 million or more gasoline gallon equivalents per year (or any such contract that, combined with previous such contracts that year, would cause the total gasoline equivalents contracted for to exceed 5 million gasoline gallon equivalents that year), we consult with the derivative committee regarding the proposed transaction, and it approves the purchase of the futures contracts.

6.             When we purchase futures contracts in accordance with paragraph 5 above, we may purchase additional futures contracts to hedge our estimated exposure to the basis differential between: (a) the price of natural gas at the NYMEX Henry Hub delivery point, and (b) the price of natural gas at the customer’s delivery point.

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7.                                       We will not sell or otherwise dispose of a futures contract during the duration of the associated fixed-price sales contract.

8.                                       We will attempt to qualify all futures contracts for hedge accounting as cash flow hedges under SFAS  133.

Due to the restrictions of our revised hedging policy, as well as the rising cost of futures contracts resulting from the loss of Mr. Pickens’ guarantee to Sempra, 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

Our discussion and analysis of our financial condition and results of operations is based upon our financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of financial statements requires management to make estimates and judgments that affect the reported amounts of assets and liabilities, revenue and expenses, and disclosures of contingent assets and liabilities as of the date of the financial statements. On a periodic basis, we evaluate our estimates, including those related to revenue recognition, accounts receivable reserves, notes receivable reserves, inventory reserves, asset retirement obligations, derivative values, income taxes, and the market value of equity instruments granted as stock-based compensation, among others. We use historical experience, market quotes, and other assumptions as the basis for making estimates. Actual results could differ from those estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our financial statements.

Revenue Recognition

We recognize revenue on our gas sales and for our O&M services in accordance with SEC Staff Accounting Bulletin No. 104, Revenue Recognition, which requires that four basic criteria must be met before revenue can be recognized: (1) persuasive evidence of an arrangement exists; (2) delivery has occurred and title and the risks and rewards of ownership have been transferred to the customer or services have been rendered; (3) the price is fixed or determinable; and (4) collectability is reasonably assured. Applying these factors, we typically recognize revenue from the sale of natural gas at the time fuel is dispensed or, in the case of LNG sales agreements, delivered to the customer’s storage facility. We recognize revenue from operation and maintenance agreements as we provide the O&M services.

In certain transactions with our customers, we agree to provide multiple products or services, including construction of and either leasing or sale of a station, providing operations and maintenance to the station, and sale of fuel to the customer. We evaluate the separability of revenues for deliverables based on the guidance set forth in EITF No. 00-21, which provides a framework for establishing whether or not a particular arrangement with a customer has one or more deliverables. To the extent we have adequate objective evidence of the values of separate deliverable items under a contract, we allocate the revenue from the contract on a relative fair value basis at the inception of the arrangement. If the arrangement contains a lease, we use the existing evidence of fair value to separate the lease from the other deliverables.

We account for our leasing activities in accordance with SFAS No. 13, Accounting for Leases. Our existing station leases are sales-type leases, giving rise to profit at the delivery of the leased station. Unearned revenue is amortized into income over the life of the lease using the effective interest method. For those arrangements, we recognize gas sales and operations and maintenance service revenues as earned from the customer on a volume-delivered basis.

We recognize revenue on fueling station construction projects where we sell the station to the customer using the completed contract method in AICPA Statement of Position 81-1, Accounting for Performance of Construction Type and Certain Production Type Contracts.

Derivative Activities

We account for our derivative instruments, specifically our futures contracts, 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. Our derivatives did not qualify for hedge accounting under SFAS 133 for the years ended December 31, 2004, 2005 and 2006. As such, changes in the fair value of the derivatives for the years ended December 31, 2004, 2005 and 2006, were recorded directly to our consolidated statements of operations. We determine the fair value of our derivatives at the end of each reporting period based on quoted market prices from the NYMEX. We did not have any derivative instruments during the first nine months of 2007.

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We record gains or losses realized on our derivative instruments during the period in the line item derivative (gains) losses in our consolidated statements of operations. We also mark-to-market our open positions at the end of each reporting period with the resulting gain or loss recorded to derivative (gains) losses in our consolidated statements of operations.

Fixed Price and Price Cap Sales Contracts

Our contracts to sell CNG and LNG at a fixed price or a variable price subject to a cap are, for accounting purposes, firm commitments, and U.S. generally accepted accounting principles do not require or allow us to record a loss until the delivery of the gas and corresponding sale of the product occurs. When we enter into these fixed price or price cap contracts with our 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 gas typically develops after we enter into the sales contract. We have entered into several contracts to sell LNG or CNG to customers at a fixed price or an index-based price that is subject to a fixed price cap. We have also generally entered into natural gas futures contracts to offset economically the adverse impact of rising natural gas prices. We have also periodically sold the underlying futures contracts related to our fixed price and price cap contracts. At September 30, 2007, we did not own any futures contracts related to our fixed price and price cap contracts. Since entering into the fixed price and price cap sales contracts, the price of natural gas has generally increased.

From an accounting perspective, during periods of rising natural gas prices, our futures contracts have generally been marked-to-market through the recognition of a derivative asset and a corresponding derivative gain in our statements of operations. However, because our contracts to sell LNG or CNG to our 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 our statements of operations during this historical period of rising natural gas prices for the future commitments under these contracts. As a result, our statements of operations do not reflect our 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).

The following table summarizes important information regarding our fixed price and price cap supply contracts under which we are required to sell fuel to our customers as of September 30, 2007:

(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 to 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 embedded in the customer’s contract.

The price of natural gas has generally increased since we entered into these contracts and fixed or capped the price of CNG or LNG that we sell to the customers. If these contracts had a notional amount as defined under GAAP, then the contracts would be considered derivatives and we would record a loss based on estimated future volumes and the estimated excess of current market prices for natural gas above the cost of the natural gas commodity component of our customer’s fixed price or price cap. However, because the contracts have no minimum purchase requirements, they are not considered derivatives and any estimated future losses under these contracts cannot be accrued in our financial statements under GAAP and we recognize the actual results of performing under the contract as the fuel is delivered. If we applied a derivative valuation methodology to these contracts using estimated volumes along with other assumptions, including forward pricing curves and discount rates, we estimate our pre-tax net income would have been lower (higher) by the following ranges for the periods indicated:

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At September 30, 2007, based on natural gas futures prices as of that date, we estimate we will incur between $5.0 million and $6.2 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, 2007, and these estimates may change based on future natural gas prices and may be significantly higher or lower.

Our volumes under these contracts, in gasoline gallon equivalents, expire as follows:

These amounts are based on estimates involving a high degree of judgment and actual results may vary materially from these estimates. These amounts have not been recorded in our statements of operations as they are non-GAAP.

Income Taxes

We compute income taxes under the asset and liability method. This method requires the recognition of deferred tax assets and liabilities for temporary differences between the financial reporting basis and the tax basis of our assets and liabilities. The impact on deferred taxes of changes in tax rates and laws, if any, are applied to the years during which temporary differences are expected to be settled and are reflected in the consolidated financial statements in the period of enactment. We record a valuation allowance against any deferred tax assets when management determines it is more likely than not that the assets will not be realized. When evaluating the need for a valuation analysis, we use estimates involving a high degree of judgment including projected future income and the amounts and estimated timing of the reversal of any deferred tax liabilities.

Our income tax benefit was $9.0 million in the quarter ended September 30, 2006, which includes an increase in the valuation allowance of $17.6 million. In the “Management’s Discussion and Analysis of Financial Condition Results of Operations — Quarterly Results of Operations” section previously filed in our initial public offering prospectus filed with the SEC on May 25, 2007, this increase in the valuation allowance was reflected in the quarter ended December 31, 2006. 

Stock-Based Compensation

Effective January 1, 2006, we account for stock options granted using Statement of Financial Accounting Standards
No. 123(R), Share-Based Payment, (SFAS 123(R))which has replaced SFAS 123 and APB 25. Under SFAS 123(R), companies are no longer able to account for share-based compensation transactions using the intrinsic method in accordance with APB 25, but are required to account for such transactions using a fair-value method and recognize the expense in the statements of operations. We adopted the provisions of SFAS 123(R) using the prospective transition method. Under the prospective transition method, only new awards, or awards that have been modified, repurchased or cancelled after January 1, 2006 are accounted for using the fair value method.

We accounted for awards outstanding as of December 31, 2005 using the accounting principles under SFAS 123. Under SFAS 123, for options granted before January 1, 2006, the fair value of employee stock options was estimated using the Black-Scholes option pricing model, which requires the use of management’s judgment in estimating the inputs used to determine fair value. We elected, under the provisions of SFAS 123, to account for employee stock-based compensation under APB 25 during the years ended December 31, 2004 and 2005. In the statements of operations, we recorded no compensation expense in 2004 and 2005 because the fair value of our common stock was equal to the exercise price on the date of grant of the options. Therefore, there was no “intrinsic” value to recognize in the statements of operations. However, the footnotes to our consolidated financial statements set forth in our prospectus dated May 25, 2007 (and filed with the SEC on May 25, 2007) disclose the impact on net income in 2004 and 2005 of using the grant date fair value using the Black-Scholes option pricing model.

As of December 31, 2005, there were no unvested stock options. Therefore, the impact of SFAS  123(R) has been reflected in the condensed consolidated statements of operations for share-based awards granted in 2006 and 2007.

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Impairment of Goodwill and Long-lived Assets

We assess our goodwill for impairment at least annually (or more frequently if there is an indicator of impairment) based on Statement of Financial Accounting Standards No. 142 (SFAS 142), Goodwill and Other Intangible Assets. An initial assessment of impairment is made by comparing the fair value of the operations with goodwill, as determined in accordance with SFAS 142, to the book value. If the fair value is less than the book value, an impairment is indicated and we must perform a second test to measure the amount of the impairment. In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the operations with goodwill from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculated implied fair value of the goodwill, we will record an impairment charge. We performed our annual tests of goodwill as of December 31, 2004, 2005 and 2006, and there was no impairment indicated. There was no indication of impairment from January 1, 2007 through September 30, 2007.

Recently Issued Accounting Pronouncements

In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48), which prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. The adoption of FIN 48 did not have a material impact on our financial statements.

In June 2006, the FASB ratified its consensus on EITF Issue No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (EITF 06-3). The scope of EITF 06-3 includes any tax assessed by a governmental authority that is imposed concurrent with or subsequent to a revenue-producing transaction between a seller and a customer and excludes taxes that are assessed on gross receipts or that are an inventoriable cost. For taxes within the scope of this issue that are significant in amount, the consensus requires the following disclosures: (i) the accounting policy elected for these taxes and (ii) the amount of the taxes reflected gross in the income statement on an interim and annual basis for all periods presented. The consensus is effective for interim and annual periods beginning after December 15, 2006. We have historically presented sales taxes and excise taxes on sales to our customers on a net basis in our financial statements both prior to and subsequent to the adoption of EITF 06-3.

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 is effective for fiscal years beginning after November 15, 2007 and all interim periods within those fiscal years. Earlier application is permitted provided that the reporting entity has not yet issued interim or annual financial statements for that fiscal year. We are currently evaluating the impact, if any, that SFAS 157 may have on our financial statements.

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. If elected, SFAS 159 will be effective as of the beginning of the first fiscal year that begins after November 15, 2007, with earlier adoption permitted if all of the requirements of SFAS 157 are adopted. We are currently evaluating the impact, if any, that SFAS 159 may have on our financial statements.

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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, 2007 Compared to Three Months Ended September 30, 2006

 Revenue.    Revenue increased by $7.0 million to $29.2 million in the three months ended September 30, 2007, from $22.2 million in the three months ended September 30, 2006. This increase was primarily the result of an increase in the number of CNG and LNG gallons delivered from 18.2 million gasoline gallon equivalents in the third quarter of 2006 to 20.0 million gasoline gallon equivalents in the third quarter of 2007. One of our new transit customers (Long Island Bus, NY) and additional buses at one of our current customers (Foothill Transit, California) together accounted for 1.7 million gasoline gallon equivalents of the increase. The remaining increase in gasoline gallon equivalents delivered was due to the addition of other smaller new customers and growth from our existing customers. Revenue also increased between periods as we recorded $4.5 million of revenue related to fuel tax credits in the third quarter of 2007, which were not included in the prior period as the credits first became available in October 2006.

Cost of sales.    Cost of sales increased by $2.1 million to $20.3 million in the three months ended September 30, 2007, from $18.2 million in the three months ended September 30, 2006. This increase was primarily the result of an increase in costs related to delivering more CNG and LNG between periods.

Derivative losses.    We incurred derivative losses of $65.0 million in the three months ended September 30, 2006, related to mark-to-market losses recorded on certain futures contracts related to future periods. We incurred no derivative gains or losses during the three months ended September 20, 2007 because we did not own any derivative instruments during this period.

Selling, general and administrative.    Selling, general and administrative expenses increased by $3.9 million to $9.5 million in the three months ended September 30, 2007, from $5.6 million in the three months ended September 30, 2006. A significant portion of this increase related to $1.6 million of stock option expense recorded in the third quarter of 2007 associated with stock options we granted to our employees and directors in May 2007 and in September 2007. In addition, salaries and benefits increased between periods by $0.7 million, primarily related to increased salaries and compensation due to our executive officers and the hiring of additional employees. Our professional service fees increased $0.6 million between periods primarily for legal, audit and consulting services related to our status as a public company. Our bad debt expense increased $0.2 million between periods as we provided a reserve against loans made to a vehicle manufacturer during the three months ended September 30, 2007. Our business insurance costs also increased $0.2 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 $0.2 million to $1.8 million in the three months ended September 30, 2007, from $1.6 million in the three months ended September 30, 2006. This increase was primarily the result of additional depreciation expense in the three months ended September 30, 2007 related to increased property and equipment balances between periods, primarily related to our expanded station network and fleet of LNG tanker trailers.

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Interest income, net.    Interest income, net, increased by $1.0 million from $0.4 million in the three months ended September 30, 2006, to $1.4 million for the three months ended September 30, 2007. This increase was primarily the result of an increase in interest income in the three months ended September 30, 2007 due to higher average cash balances on hand in the third quarter of 2007 associated with the proceeds received from our initial public offering in May 2007.

Other expense, net.    There was no significant change in other expense, net, between the three months ended September 30, 2006 and the three months ended September 30, 2007.

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

Revenue.    Revenue increased by $23.2 million to $88.0 million in the nine months ended September 30, 2007, from $64.8 million in the nine months ended September 30, 2006. This increase was primarily the result of an increase in the CNG and LNG delivered between periods from 50.7 million gasoline gallon equivalents in the first nine months of 2006 to 57.1 million gasoline gallon equivalents in the first nine months of 2007. One of our new transit customers (Long Island Bus, NY) and one of our new airport customers (Los Angeles International Airport shuttle busses) together accounted for 4.1 million gasoline gallon equivalents of the increase. The remaining increase in gasoline gallon equivalents delivered was due to the addition of other smaller new customers and growth from our existing customers. Revenue also increased in the first nine months of 2007 as we recorded $12.8 million of revenue related to fuel tax credits during the period, which were not included in the prior period as the credits first became available in October 2006. We also experienced an increase between periods of $3.1 million in station construction revenue. Offsetting these increases was a decrease in our average price per gallon between periods. Our average price per gallon, excluding tax credits, was $1.25 in the first nine months of 2007, which represents a $.02 per gallon decrease from the first nine months of 2006.

Cost of sales.    Cost of sales increased by $9.2 million to $64.1 million in the nine months ended September 30, 2007, from $54.9 million in the nine months ended September 30, 2006. This increase was primarily the result of an increase in costs related to delivering more CNG and LNG between periods. Also contributing to the increase in cost of sales between periods is a $2.8 million increase in costs related to construction activities during the nine month period ended September 30, 2007. In addition, our cost of sales increased between periods as our average cost per gallon rose to $1.12 in the first nine months of 2007, which represents a $.04 per gallon increase over the first nine months of 2006.

Derivative losses.    We incurred derivative losses of $65.3 million in the nine months ended September 30, 2006, primarily related to mark-to-market losses recorded on certain futures contracts related to future periods. We incurred no derivative gains or losses during the nine months ended September 30, 2007 because we did not own any derivative instruments during this period.

Selling, general and administrative.    Selling, general and administrative expenses increased by $11.4 million to $26.3 million in the nine months ended September 30, 2007, from $14.9 million in the nine months ended September 30, 2006. The increase was primarily related to recording $5.4 million of stock option expense in the second and third quarters of 2007 associated with the stock options we granted to our employees and directors in May 2007 and in September 2007. There was an increase of $2.1 million in salaries and benefits between periods primarily related to the increased compensation due to our executive officers and the hiring of additional employees. Our employee headcount increased from 96 at September 30, 2006 to 118 at September 30, 2007. In addition, our rent expense increased $0.2 million between periods as we acquired additional office space between periods and our travel and entertainment expenses increased $0.4 million between periods, primarily related to increased travel related to our sales team. Our marketing expenses increased $0.9 million between periods, primarily due to certain advertising we conducted related to our refuse market segment and in the Ports of Los Angeles and Long Beach. Our bad debt expense increased $1.0 million between periods as we provided a reserve against loans made to a vehicle manufacturer and two of our vehicle financing customers during the nine months ended September 30, 2007. Our professional service fees increased $0.9 million between periods primarily for legal, audit and consulting services related to our status as a public company. Our business insurance costs also increased $0.3 million between periods, primarily due to premium increases in our directors’ and officers’ insurance between periods, and our credit card fees increased $0.2 million between periods as more of our retail customers are using credit cards to purchase their fuel.

Depreciation and amortization.    Depreciation and amortization increased by $0.9 million to $5.1 million in the nine months ended September 30, 2007, from $4.2 million in the nine months ended September 30, 2006. This increase was primarily related to the result of additional depreciation expense in the nine months ended September 30, 2007 related to increased property and equipment balances between periods, primarily related to our expanded station network and fleet of LNG tanker trailers.

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Interest income, net.    Interest income, net, increased by $1.5 million from $0.8 million in the nine months ended September 30, 2006, to $2.3 million for the nine months ended September 30, 2007. This increase was primarily the result of a decrease in interest expense in the nine months ended September 30, 2007 due to the conversion of $4 million of convertible notes in April 2006, which eliminated the interest expense on these notes. In addition, interest income for the nine months ended September 30, 2007 increased in comparison to the nine months ended September 30, 2006 due to higher average cash balances on hand in the first nine months of 2007 associated with the proceeds received from our initial public offering in May 2007.

Other expense, net.    Other expense, net, increased by $0.2 million to $0.2 million of expense in the nine months ended September 30, 2007. The increase was primarily related to costs related to station closures recorded in the second and third quarters of 2007.

Seasonality and Inflation

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

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

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. 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 financed our operations in the first nine months of 2007 primarily through cash provided by operations and financing activities. At September 30, 2007, we had total cash and cash equivalents of $74.8 million compared to $0.9 million at December 31, 2006.

Cash provided by operating activities was $8.6 million for the nine months ended September 30, 2007, compared to cash used in operating activities of $37.2 million for the nine months ended September 30, 2006. The change in operating cash flow was primarily related to the change in our margin deposits between periods. In the first nine months of 2006, we made net margin deposits on futures contracts of $30.9 million, and in the first nine months of 2007, we received a refund of $22.9 million of margin deposits. The $22.9 million of margin deposits received in 2007 is recorded in other receivables as these deposits were transferred to other receivables in the fourth quarter of 2006 in connection with a transaction we completed with Boone Pickens in December 2006. For more information, see “Risk Management Activities – August 2006 Purchase of Futures Contracts and December 2006 Assumption by Boone Pickens” above. Offsetting this increase are (i) increases in our fuel tax credit receivable between periods, the majority of which we receive on an annual basis after we file our income tax return, and (ii) an increase between periods in the deposits we made on the production of certain LNG trucks we anticipate will be operated in the Ports of Los Angeles and Long Beach. We also experienced an increase in cash provided by operating activities between periods due to a reduction in our income taxes paid between periods of $6.3 million.

Cash used in investing activities was $45.1 million for the nine months ended September 30, 2007, compared to $11.3 million for the nine months ended September 30, 2006. The $33.8 million increase between periods was primarily due to increased purchases of property and equipment and increased construction in progress activity in the first nine months of 2007, including approximately $17 million that we spent on developing our LNG liquefaction plant in California. We also purchased $14.8 million of short-term investments in the third quarter of 2007 with excess cash balances.

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Cash provided by financing activities for the nine months ended September 30, 2007 was $110.3 million, compared to cash provided by financing activities of $21.2 million for the nine months ended September 30, 2006. The $89.1 million increase between periods is primarily attributable to the net proceeds of $110.2 million we received from our initial public offering in May 2007, as compared to the proceeds of $22.0 million we received from the issuance of common stock during the nine months ended September 30, 2006.

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, if necessary, through debt or equity financings. We believe our sources of liquidity will be sufficient to meet the cash requirements of our operations for at least the next twelve months.

Capital Expenditures

We expect to make capital expenditures, net of grant proceeds, of approximately $19.3 million in 2007 to construct new natural gas fueling stations, purchase LNG tanker trailers, and for general corporate purposes. Additionally, we have budgeted approximately $65 million over the course of 2007 and 2008 to construct an LNG liquefaction plant in California which we are in the initial stages of building and anticipate will be operational in the summer of 2008. We also anticipate using $15 to $20 million from the proceeds of our initial public offering to finance the purchase of natural gas vehicles by our customers.

Contractual Obligations

The following represents the scheduled maturities of our contractual obligations as of September 30, 2007:

(a)                                  Consists of obligations under a lease of capital equipment used to finance such equipment. Amounts do not include interest as it is immaterial.

(b)                                 Consists of various space and ground leases for our 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 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.

(d)                                 Consists of our obligations to fund various fueling station construction projects, net of amounts funded through September 30, 2007, and excluding contractual commitments related to station sales contracts.

(e)                                  Consists of our obligations to fund certain vehicles under binding purchase agreements and our commitments under binding purchase agreements we have entered into to acquire certain equipment and services related to the construction of our LNG plant in California.

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Off-Balance Sheet Arrangements

At September 30, 2007, we had the following off-balance sheet arrangements:

•                                          outstanding standby letters of credit totaling $16,000,

•                                          outstanding surety bonds for construction contracts and general corporate purposes totaling $5.5 million,

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

•                                          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 standby letters of credit primarily to support facility leases and 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 standby letters of credit or 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.

We have entered into contracts with two vendors to purchase LNG that require us to purchase minimum volumes from the vendors. Both of the contracts expire in June 2008. The minimum commitments under these two contracts are included in the table set forth under “Take-or-pay” LNG purchase contracts above.

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 are in the initial stages of building an LNG liquefaction plant. We have budgeted approximately $65 million over the course of 2007 and 2008 to construct this plant. The lease is for an initial term of 30 years, beginning on the date that the plant commences operations, and requires annual base rent payments of $230,000 per year, plus $130,000 per year for each 30,000,000 gallons of production capacity, 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. Our obligations under the lease are contingent on us obtaining the necessary permits and approvals required in the lease related to the construction and operation of the LNG liquefaction plant, which are in process. As the payments are contingent obligations, they are not 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 63% of our cost of sales for 2006 and 59% of our cost of sales for the nine months ended September 30, 2007. Prices for natural gas over the seven-year and nine-month period from December 31, 1999 through September 30, 2007, based on the NYMEX daily futures data, has ranged from a low of $1.65 per Mcf to a high of $19.38 per Mcf. At September 30, 2007, the NYMEX index price of natural gas was $5.23 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 No. 133, Accounting for Derivative Instruments and Hedging Activities. 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, 2004, 2005 and 2006, and changes in the fair value of the derivatives were recorded directly to our consolidated statements of operations at the end of each reporting period. We did not own any derivative instruments during the first nine months of 2007.

The fair value of the futures contracts we use is based on quoted prices in active exchange traded or over the counter markets. 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 three or nine months ended September 30, 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. 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 our fixed price and price cap sales contracts as of September 30, 2007. Market risk is estimated as the potential loss resulting from a hypothetical 10.0% adverse change in the fair value of natural gas prices. The results of this analysis, which assumes natural gas prices are in excess of our customer’s price cap arrangements, and may differ from actual results, are as follows:

As of September 30, 2007 we did not have any futures contracts outstanding.

Item 4. – Controls and Procedures

Disclosure Controls and Procedures

We maintain disclosure controls and procedures and internal controls that are designed to provide reasonable, but not absolute, assurance that information required to be disclosed in our Exchange Act reports 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 as of the end of the period covered by this report. Based on the foregoing, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

In addition, an evaluation was performed under the supervision of and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of any change in our internal control over financial reporting that has occurred during our last fiscal quarter that has materially affected, or is reasonably likely to affect materially, our internal control over financial reporting. There has been no change in our internal control over financial reporting during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. – OTHER INFORMATION

Item 1. – Legal Proceedings

We are from time to time involved in various lawsuits, legal proceedings or claims that arise in the ordinary course of business. We do not believe any such legal proceedings or claims will have, individually or in the aggregate, a material adverse effect on our business, liquidity, results of operations or financial position. However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm our business.

Item 1A. – Risk Factors

An investment in our company involves a high degree of risk. In addition to the other information included in this report, we urge you to carefully consider the risk factors set forth in our Form 10-Q for the quarter ended June 30, 2007 (filed with the SEC on August 14, 2007) in evaluating an investment in our company. We urge you to consider these matters in conjunction with the other information included or incorporated by reference in this report.

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

Use of Proceeds

Our initial public offering of common stock was effected through a Registration Statement on Form S-1 (File No. 333-137124) that was declared effective by the Securities and Exchange Commission on May 24, 2007. On May 31, 2007, 10,000,000 shares of common stock were sold on our behalf at an initial public offering price of $12.00 per share (for aggregate gross offering proceeds of $120.0 million) managed by W.R. Hambrecht + Co., LLC, Simmons & Company International, Susquehanna Financial Group, LLP, and NBF Securities (USA) Corp. In addition, on June 22, 2007, in connection with the exercise of the underwriters’ over-allotment option, 1,500,000 additional shares of common stock were sold by selling stockholders at the initial public offering price of $12.00 per share (for aggregate gross offering proceeds of $18.0 million). We received no proceeds from the sale of shares by selling stockholders. The offering terminated following the closing of the over-allotment sale.

We paid to the underwriters underwriting discounts totaling approximately $7.0 million in connection with the offering. In addition, through September 30, 2007, we incurred additional costs of approximately $4.5 million in connection with the offering, which when added to the underwriting discounts paid by us, amounts to total expenses of approximately $11.5 million. Thus, the net offering proceeds to us, after deducting underwriting discounts and offering expenses, were approximately $108.5 million through September 30, 2007. No offering expenses were paid directly or indirectly to any of our directors or officers (or their associates) or persons owning ten percent or more of any class of our equity securities or to any other affiliates.

Through September 30, 2007, we have used the net proceeds from the offering as follows:

•                                          construction of our LNG liquefaction plant in California ($9.4 million),

•                                          construction and installation of CNG and LNG stations ($1.4 million),

•                                          financing customer vehicle purchases ($1.2 million), and

•                                          working capital ($8.9 million).