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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC  20549

FORM 10-Q

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

For the quarterly period ended June 30, 2008

Commission File Number: 001-33480

CLEAN ENERGY FUELS CORP.

(Exact name of registrant as specified in its charter)

3020 Old Ranch Parkway, Suite 200, Seal Beach CA 90740

(Address of principal executive offices, including zip code)

(562) 493-2804

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

As of August 11, 2008, there were 44,310,720 shares of the registrant’s common stock, par value $0.0001 per share, issued and outstanding.

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

INDEX

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PART I. – FINANCIAL INFORMATION

Item 1. – Financial Statements (Unaudited)

Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Balance Sheets

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

See accompanying notes to condensed consolidated financial statements.

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Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Statements of Operations

For the Three Months and Six Months Ended

June 30, 2007 and 2008

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

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Clean Energy Fuels Corp.

Condensed Consolidated Statements of Cash Flows

For the Six Months Ended June 30, 2007 and 2008

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — General

Nature of Business:    Clean Energy Fuels Corp. (the “Company”) is engaged in the business of selling natural gas fueling solutions to its customers primarily in the United States and Canada. The Company has a broad customer base in a variety of markets including public transit, refuse, airports and regional trucking. Clean Energy operates or supplies approximately 170 natural gas fueling locations in California, Texas, Colorado, Maryland, New York, New Mexico, Nevada, Washington, Massachusetts, Georgia, Wyoming and Arizona within the United States, and in British Columbia and Ontario within Canada. The Company also generates revenue through operation and maintenance agreements with certain customers, through building and selling or leasing natural gas fueling stations to its customers, and through financing its customers’ vehicle purchases. In April 2008, the Company opened its first CNG station in Lima, Peru through the Company’s joint venture, Clean Energy del Peru.

Basis of Presentation:    The accompanying interim unaudited condensed consolidated financial statements include the accounts of the Company and its subsidiaries, and, in the opinion of management, reflect all adjustments, which include only normal recurring adjustments, necessary to state fairly the Company’s financial position, results of operations and cash flows for the three and six months ended June 30, 2007 and 2008. All intercompany accounts and transactions have been eliminated in consolidation. The three and six month periods ended June 30, 2007 and 2008 are not necessarily indicative of the results to be expected for the year ending December 31, 2008 or for any other interim period or for any future year.

Certain information and disclosures normally included in the notes to consolidated financial statements have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), but the resultant disclosures contained herein are in accordance with accounting principles generally accepted in the United States of America as they apply to interim reporting. The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements as of and for the year ended December 31, 2007 that are included in the Company’s Annual Report on Form 10-K filed with the SEC.

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, from time to time, enters into natural gas futures contracts that are over-the-counter swap transactions that convert its index-based gas supply arrangements to fixed-price arrangements. The Company accounts for its derivative instruments in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (SFAS 133).  SFAS 133 requires the recognition of all derivatives as either assets or liabilities in the consolidated balance sheet and the measurement of those instruments at fair value.  Historically, the Company’s derivative instruments have not qualified for hedge accounting under SFAS 133.  The Company did not have any derivative instruments during the year ended December 31, 2007 and through March 31, 2008.  At June 30, 2008, the Company had purchased certain derivative instruments related to a fixed-price bid on a LNG supply contract (see note 5).

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The Company marks to market its open futures position at the end of each period and records the net unrealized gain or loss during the period in derivative (gains) losses in the consolidated statements of operations.  For the three and six month periods ended June 30, 2008, the Company recorded unrealized gains of $5.7 million related to its futures contracts.

In July 2008, the Company sold certain contracts related to the derivative instruments it purchased in April 2008 and realized a loss of $6.0 million (see note 5), which will be reflected in the financial statements for the quarter ending September 30, 2008.

The Company is required to make certain deposits on its futures contracts, should any exist. At June 30, 2008, the Company had made $1.2 million of margin deposits related to its futures contracts, of which $0.4 million was current as of June 30, 2008.

Note 5 — Fixed Price and Price Cap Sales Contracts

The Company enters 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.  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 June 30, 2008:

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

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

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

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At June 30, 2008, we estimate we will incur between $5.9 million and $7.2 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 June 30, 2008, and these estimates may change based on future natural gas prices and may be significantly higher or lower. Our estimated volumes under these contracts, in gasoline gallon equivalents, expire as follows:

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

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

Note 6 — Other Receivables

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

Note 7 — Land, Property and Equipment

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

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Note 8 — Accrued Liabilities

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

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

Note 10 — Comprehensive Income

The following table presents the Company’s comprehensive income for the six months ended June 30, 2007 and 2008:

Note 11 — Stock-Based Compensation

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

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Stock Options

The following table summarizes all stock option activity during the six months ended June 30, 2008:

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

Based on these assumptions, the weighted average grant date fair value of options granted during the six months ended June 30, 2008 was $8.10.

Note 12 — Use of Estimates

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

Note 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.

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As of June 30, 2008, the Company has remaining contractual commitments related to constructing its LNG liquefaction plant in California of $22.7 million.

Note 14 — Income Taxes

FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48), requires that the Company recognize the impact of a tax position in its financial statements if the position is more likely than not of being sustained by the taxing authority upon examination, based on the technical merits of the position.  FIN 48 requires the Company to accrue interest based on the difference between the tax position recognized in the financial statements and the amount claimed on the return.  The net interest incurred was immaterial for the six months ended June 30, 2007 and 2008.  FIN 48 further requires that penalties be accrued if the tax position does not meet the minimum statutory threshold to avoid penalties.  No penalties have been accrued by the Company.  The Company’s unrecognized tax benefits as of June 30, 2008 are unchanged from December 31, 2007.

Income tax returns are subject to audit by federal, state and local governments, sometimes several years after a return is filed.  The Company is currently under audit by the Internal Revenue Service for tax years 2005 and 2006 and the State of California for tax years 2004 and 2005.  Disputes may arise during the course of such audits as to facts and different interpretations of tax law.

Note 15 — Recently Adopted Accounting Changes

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

As of June 30, 2008, the Company’s financial assets consisted of short-term investments and natural gas futures contracts. The Company uses quoted market prices to measure fair value of its short-term investments.  The Company uses quoted forward price curves, discounted to reflect the time value of money, to value its natural gas futures contracts.

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

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

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

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

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The following table reflects the fair value as defined by SFAS 157, of the Company’s short-term investment securities and natural gas futures contracts:

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

The discussion in this section contains forward-looking statements. These statements relate to future events or our future financial performance. We have attempted to identify forward-looking statements by terminology such as “anticipate,” “believe,” “can,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “should,” “would” or “will” or the negative of these terms or other comparable terminology, but their absence does not mean that a statement is not forward-looking. These statements are only predictions and involve known and unknown risks, uncertainties and other factors, which could cause our actual results to differ from those projected in any forward-looking statements we make. See “Risk Factors” in Part I, Item 1A of our Form 10-K for the year ended December 31, 2007, filed with the SEC on March 19, 2008, for a discussion of some of these risks and uncertainties. This discussion should be read with our financial statements and related notes included elsewhere in this report.

We provide natural gas solutions for vehicle fleets primarily in the United States and Canada.  In April 2008, we opened our first CNG station in Lima, Peru, through our joint venture, Clean Energy del Peru.  Our primary business activity is selling CNG and LNG vehicle fuels to our customers. We also build, operate and maintain fueling stations, and help our customers acquire and finance natural gas vehicles and obtain local, state and federal clean air incentives. Our customers include fleet operators in a variety of markets, such as public transit, refuse hauling, airports, taxis and regional trucking.

Overview

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

Sources of revenue. We generate the vast majority of our revenue from selling CNG and LNG to our customers. The balance of our revenue is provided by operating and maintaining natural gas fueling stations, designing and constructing natural gas fueling stations, and financing our customers’ natural gas vehicle purchases.

Key operating data. In evaluating our operating performance, our management focuses primarily on (1) the amount of CNG and LNG gasoline gallon equivalents delivered (which we define as the volume of gasoline gallon equivalents we sell to our customers plus the volume of gasoline gallon equivalents dispensed to our customers at stations where we provide O&M services but do not directly sell the CNG or LNG) and (2) our revenue and net income (loss). The following table, which you should read in conjunction with our condensed consolidated financial statements and notes contained elsewhere in this report, presents our key operating data for the years ended December 31, 2005, 2006 and 2007 and for the three and six months ended June 30, 2007 and 2008:

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Key trends in 2005, 2006, and 2007.  Vehicle fleet demand for natural gas fuels increased during the three years ended December 31, 2005, 2006 and 2007. We believe this growth in demand was attributable primarily to the rising prices of gasoline and diesel relative to CNG and LNG during these periods and increasingly stringent environmental regulations affecting vehicle fleets. We capitalized on this growing demand by securing new fleet customers in a variety of markets, including public transit, refuse hauling, airports, taxis and regional trucking.

The number of fueling stations we served grew from 147 at December 31, 2004 to 170 at December 31, 2007 (a 15.7% increase). The amount of CNG and LNG gasoline gallon equivalents we delivered from 2005 to 2007 increased by 32.6%. Our cost of sales also increased during these periods, which was attributable primarily to the increased price of natural gas and increased costs related to delivering CNG and LNG to our customers.

Anticipated future trends. We anticipate that, over the long term, the prices for gasoline and diesel will continue to be higher than the price of natural gas as a vehicle fuel, and more stringent emissions requirements will continue to make natural gas vehicles an attractive alternative to traditional gasoline and diesel powered vehicles. We believe there will be significant growth in the consumption of natural gas as a vehicle fuel generally, and our goal is to capitalize on this trend and enhance our leadership position as this market expands. We have built a natural gas fueling station, and plan to build additional natural gas fueling stations, that will provide LNG to fleet vehicles at the Ports of Los Angeles and Long Beach. We also anticipate expanding our sales of CNG and LNG in the other markets in which we operate, including public transit, refuse hauling and airports. Consistent with the anticipated growth of our business, we also expect that our operating costs will increase, primarily from the logistics of delivering more CNG and LNG to our customers, as well as from the anticipated expansion of our station network. We also continue to incur significant costs related to the LNG liquefaction plant we are in the process of building in California. Additionally, we have and will continue to increase our sales and marketing team 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. Our business plan for the last six months of 2008 calls for approximately $62.3 million in capital expenditures (primarily related to building an LNG liquefaction plant in California and constructing new fueling stations) and $2.2 million for financing natural gas vehicle purchases by our customers.  As of the date of this report, we anticipate we will need to raise at least $6.0 million of additional capital during the remainder of 2008 to fund our LNG plant and station construction capital expenditures and vehicle financing program for the remainder of 2008.  We may also seek to acquire companies or assets in the natural gas fueling infrastructure, services and production industries, and we will have to raise additional capital as necessary to fund any such acquisitions, which are not budgeted for in our 2008 business plan. 

As reported in our Form 10-K for the year ended December 31, 2007 and filed with the SEC on March 19, 2008, we previously anticipated that we would need to raise approximately $40 million of additional capital during 2008 to fund our capital expenditure program in full.  The decrease in our anticipated additional capital needs with respect to our 2008 business plan is primarily a result of accelerated collection of fuel tax credits, which the IRS now allows us to claim on a quarterly instead of annual basis, and lower projected costs for station construction activity during 2008 as a result of revised construction schedules.  If we are unable to raise sufficient capital in the debt or equity markets to finance our 2008 business plan or any proposed strategic transactions, we will be forced to suspend or curtail certain expansion projects or be unable to execute strategic transactions to acquire complementary companies or assets which harm our business, results of operations, or future prospects.  We may be unable to raise capital through equity or debt financing on favorable terms, or at all.  For more information, see “Liquidity and Capital Resources” below.

Volatility in operating results related to futures contracts. Historically, we have purchased futures contracts from time to time to help mitigate our exposure to natural gas price fluctuations in current periods and in future periods. Gains and losses related to our futures activities, which appear in the line item derivative (gains) losses in our condensed consolidated financial statements, have materially impacted our results of operations in recent periods. For the years ended December 31, 2005, 2006 and 2007, derivative (gains) losses were $(44,067,744), $78,994,947, and $0 respectively. For the six month periods ended June 30, 2007 and 2008, derivative (gains) losses were $0 and $(5,706,981) respectively. For this reason and others, we caution investors that our past operating results may not be indicative of future results. For more information, please read “Volatility of Earnings and Cash Flows” and “Risk Management Activities” below.

Business risks and uncertainties. Our business and prospects are exposed to numerous risks and uncertainties. For more information, see “Risk Factors” in Part I, Item 1A of our Form 10-K filed with the SEC on March 19, 2008.

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Operations

We generate revenues principally by selling CNG and LNG to our vehicle fleet customers. For the six months ended June 30, 2008, CNG represented 65% and LNG represented 35% 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. Effective January 1, 2007, we no longer intend to offer price-cap contracts to our customers, but we will continue to perform our obligations under price-cap contracts we entered into before January 1, 2007. We will continue to offer fixed price contracts as appropriate and consistent with our revised natural gas hedging policy adopted in February 2007.  Our fleet customers typically are billed monthly based on the volume of CNG sold at a station. The remainder of our CNG sales are on a per fill-up basis at prices we set at the pump based on prevailing market conditions. These customers typically pay using a credit card at the station.

In April 2008, we opened our first CNG station in Lima, Peru through our joint venture Clean Energy del Peru.

LNG Sales

We sell substantially all of our LNG to fleet customers, who typically own and operate their fueling stations. We also sell a small volume of LNG to customers for non-vehicle use. We procure LNG from third-party producers and also produce LNG at our liquefaction plant in Texas. For LNG that we purchase from third-parties, we typically enter into “take or pay” contracts that require us to purchase minimum volumes of LNG at index-based rates. We deliver LNG via our fleet of 60 tanker trailers to fueling stations, where it is stored and dispensed in liquid form into vehicles. We sell LNG principally through supply contracts that are priced on either a fixed-price or index-plus basis. We also provided price caps to certain customers on the index component of their index-plus pricing arrangement for certain contracts we entered into on or prior to December 31, 2006. Effective January 1, 2007, we no longer intend to offer price-cap contracts to our customers, but we will continue to perform our obligations under price-cap contracts we entered into before January 1, 2007, including two one-year renewal periods that one of our customers is entitled to should they choose to exercise such renewals.  The renewal periods, if exercised, would obligate us to sell the customer approximately 2.1 million LNG gallons on an annual basis subject to a price cap for each renewal year.  We will continue to offer fixed price contracts as appropriate and consistent with our revised natural gas hedging policy adopted in February 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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Operation and Maintenance

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

Station Construction

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

Vehicle Acquisition and Finance

In 2006, we commenced offering vehicle finance services for some of our customers’ purchases of natural gas vehicles or the conversion of their existing gasoline or diesel powered vehicles to operate on natural gas. We loan to our customers up to 100% of the purchase price of their natural gas vehicles. We may also lease vehicles in the future. Where appropriate, we apply for and receive state and federal incentives associated with natural gas vehicle purchases and pass these benefits through to our customers. We may also secure vehicles to place with customers or pay deposits with respect to such vehicles prior to receiving a firm order from our customers, which we may be required to purchase if our customer fails to purchase the vehicle as anticipated. As of June 30, 2008, we have not generated significant 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” below. We have therefore recorded any changes in the fair market value of these contracts directly in our statements of operations in the line item derivative (gains) losses along with any realized gains or losses generated during the period. For example, we experienced derivative gains of $33.1 million and $5.7 million for the three months ended September 30, 2005 and June 30, 2008, and derivative losses of $19.9 million, $0.3 million, $65.0 million 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, September 30, 2007, December 31, 2007 and March 31, 2008. For the three months ended June 30, 2008, we recognized a $5.7 million derivative gain with respect to futures contracts purchased to hedge our exposure to a fixed price contract for which we bid (see Note 5 to the accompanying condensed consolidated financial statements), and we will recognize a $6.0 million derivative loss during the three months ending September 30, 2008 with respect to the sale of certain of these contracts. 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.  At June 30, 2008, we had $1.2 million on deposit in margin accounts.

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

Risk Management Activities

Our risk management activities, including the revised natural gas hedging policy adopted by our board of directors in February 2007 and revised by our Board of Directors on May 29, 2008 are discussed in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operation) of our annual report on Form 10-K for the year ended December 31, 2007 and our current report on Form 8-K, dated June 19, 2008, which discussion is incorporated herein by reference.

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On April 18, 2008, we purchased certain natural gas futures contracts to attempt to economically hedge our exposure to cash flow variability related to the commodity component of an LNG supply contract for which we had submitted a fixed-price bid. For the three and six month periods ended June 30, 2008, the Company recorded unrealized gains of $5.7 million related to these futures contracts.  As previously disclosed in our Form 8-K dated June 19, 2008, the supply contract for which the futures contracts were purchased was awarded to our competitor. We protested the award of the contract to our competitor and ultimately we were awarded a portion of the contract representing approximately one-third of the contract volumes. In July 2008, we then sold the futures contracts related to the portion of the contract we were not awarded. Due to the decrease in the price of natural gas between June 30, 2008 and the date the futures contracts were sold, we realized a loss of $6.0 million (see note 5 in our accompanying condensed consolidated financial statements), which will be reflected in the financial statements for the quarter ending September 30, 2008. Ultimately, we realized a net loss of $0.3 million related to the sale of the futures contracts purchased with respect to the portion of the fixed-price contract that we were not awarded. We will attempt to qualify the remaining futures contracts for hedge accounting as cash flow hedges under SFAS 133.

Critical Accounting Policies

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

Recently Issued Accounting Pronouncements

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

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

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

In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141(R), Business Combinations (“SFAS 141(R)”). SFAS 141(R) provides new accounting guidance and disclosure requirements for business combinations. SFAS 141(R) is effective for business combinations which occur in the first fiscal year beginning on or after December 15, 2008.

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

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

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

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

Results of Operations

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

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

 Revenue.   Revenue increased by $3.9 million to $34.6 million in the three months ended June 30, 2008, from $30.7 million in the three months ended June 30, 2007. This increase was primarily the result of an increase in our average price per gallon between periods. Our effective price per gallon was $1.57 in the three months ended June 30, 2008, which represents a $0.29 per gallon increase from $1.28 in the three months ended June 30, 2007. Revenue also increased between periods as we recorded $5.2 million of revenue related to fuel tax credits in the second quarter of 2008, compared to $4.4 million in the second quarter of 2007. The increases in price and fuel tax credits were offset by the decrease in the number of gallons delivered between periods from 19.3 million gasoline gallon equivalents to 18.5 million gasoline gallon equivalents. The decrease in volume was primarily related to the cancellation of an LNG O&M contract related to a facility that was relocated and a CNG supply contract with a customer who decided to procure their own natural gas supply. We also experienced a $1.0 million decrease in station construction revenues between periods.

Cost of sales.   Cost of sales increased by $6.1 million to $28.6 million in the three months ended June 30, 2008, from $22.5 million in the three months ended June 30, 2007. Our cost of sales increased between periods as our effective cost per gallon rose to $1.53 in the three months ended June 30, 2008, which represents a $0.42 per gallon increase over the three months ended June 30, 2007. Offsetting the increase in our effective cost per gallon was a decrease in station construction costs of $0.9 million between periods and a $1.3 million decrease in costs related to delivering less CNG and LNG between periods.

Derivative (gains) losses.   Derivative gains increased to $5.7 million in the three months ended June 30, 2008, from $0.0 million in the three months ended June 30, 2007. This increase was due to a gain we recognized in the three month period ended June 30, 2008 on futures contracts we purchased in April 2008 in conjunction with a fixed-price bid on a LNG supply contract we had submitted (see note 5 to the accompanying condensed consolidated financial statements), and we did not sell or own any futures contracts during the three months ended June 30, 2007.

Selling, general and administrative.   Selling, general and administrative expenses increased by $1.7 million to $12.1 million in the three months ended June 30, 2008, from $10.4 million in the three months ended June 30, 2007. A significant portion of this increase related to a $2.0 million increase in our marketing expenses due to certain advertising we conducted at the Ports of Los Angeles and Long Beach and costs we incurred to support the Clean Renewable and Clean Alternative Fuels Act (“Alternative Fuels Act”) in California. We believe that the Alternative Fuels Act represents a significant opportunity for our business. The Alternative Fuels Act, if passed by California voters, would provide financial resources for the purchase and conversion of vehicles to run on clean alternative fuels such as natural gas. Our professional service fees increased $0.4 million between periods, primarily for consulting services related to our obligations as a public company.  There was also an increase of $0.3 million in travel, meals and entertainment between periods, primarily related to increased travel by our sales team.  There was also an increase of $0.8 million in salaries and benefits between periods, primarily related to increased compensation due to our executive officers and the hiring of additional employees. Our employee headcount increased from 109 at June 30, 2007 to 133 at June 30, 2008.  These increases were offset by (i) a $1.2 million decrease in stock option expense between periods as the second quarter of 2007 included the initial vesting (which was 1/6 greater than our usual practice) of certain stock options we granted to our employees in May 2007 upon the effectiveness our registration statement on Form S-1 filed in connection with our initial public offering, and (ii) an $0.8 million decrease in our executive officers’ bonus accrual as a result of revised anticipated payouts related to the 2008 bonus plan.

Depreciation and amortization.   Depreciation and amortization increased by $0.5 million to $2.2 million in the three months ended June 30, 2008, from $1.7 million in the three months ended June 30, 2007. This increase was primarily related to the result of additional depreciation expense in the three months ended June 30, 2008 related to increased property and equipment balances between periods, primarily related to our expanded station network.

Interest income, net.   Interest income, net, decreased by $0.2 million from $0.5 million in the three months ended June 30, 2007, to $0.3 million for the three months ended June 30, 2008. This decrease was primarily the result of a decrease in interest income in the three months ended June 30, 2008 due to lower average cash balances on hand during the three months ended June 30, 2008 as compared to the second quarter of 2007, which included higher cash balances associated with the proceeds received from our initial public offering in May 2007.

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Other income (expense), net.   Other income (expense), net, was $2,000 of income in the three months ended June 30, 2008, as compared to $56,000 of expense in the three months ended June 30, 2007. The increase was primarily related to the write-off of certain costs related to station relocation in the three months ended June 30, 2007 that did not occur in the three months ended June 30, 2008.

Equity in gains (losses) of equity method investee.  During the three months ended June 30, 2008, we recognized $5,000 of equity gains related to our joint venture in Peru. The CNG station owned by the joint venture opened in April 2008.

Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007

Revenue.   Revenue increased by $5.7 million to $64.5 million in the six months ended June 30, 2008, from $58.8 million in the six months ended June 30, 2007. This increase was primarily the result of an increase in our average price per gallon between periods. Our effective price per gallon was $1.50 in the six months ended June 30, 2008, which represents a $0.23 per gallon increase from $1.27 in the six months ended June 30, 2007. Revenue also increased between periods as we recorded $9.9 million of revenue related to fuel tax credits in the first six months of 2008 compared to $8.2 million in the first six months of 2007. The increases in price and fuel tax credits were offset by the decrease in the number of gallons delivered between periods from 37.1 million gasoline gallon equivalents to 36.1 million gasoline gallon equivalents. The decrease in volume was primarily related to the cancellation of an LNG O&M contract related to a facility that was relocated and a CNG supply contract with a customer who decided to procure their own natural gas supply. We also experienced a $2.8 million decrease in station construction revenues between periods.

Cost of sales.   Cost of sales increased by $7.2 million to $51.0 million in the six months ended June 30, 2008, from $43.8 million in the six months ended June 30, 2007. Our cost of sales increased between periods as our effective cost per gallon rose to $1.41 in the six months ended June 30, 2008, which represents a $0.30 per gallon increase over the six months ended June 30, 2007. Offsetting the increase in our effective cost per gallon was the decrease in station construction costs of $2.6 million between periods and a $1.4 million decrease in costs related to delivering less CNG and LNG between periods.

Derivative (gains) losses.   Derivative gains increased to $5.7 million in the six months ended June 30, 2008, from $0.0 million in the six months ended June 30, 2007. This increase was due to a gain we recognized in the six month period ended June 30, 2008 on futures contracts we purchased in April 2008 in conjunction with a fixed-price bid on a LNG supply contract we had submitted (see note 5 to the accompanying condensed consolidated financial statements) and we did not sell or own any futures contracts during the six months ended June 30, 2007.

Selling, general and administrative.   Selling, general and administrative expenses increased by $7.0 million to $23.7 million in the six months ended June 30, 2008, from $16.7 million in the six months ended June 30, 2007. A significant portion of this increase related to a $3.7 million increase in our marketing expenses due to certain advertising we conducted related to the Ports of Los Angeles and Long Beach and costs we incurred to support the Alternative Fuels Act.  Stock option expense between periods increased $1.3 million due to options issued in 2008 for eligible new hires. There was also an increase of $1.0 million in salaries and benefits between periods primarily related to increased compensation due to our executive officers and the hiring of additional employees. Our professional service fees increased $0.8 million between periods, primarily for consulting services related to our obligations as a public company.  Our business insurance costs increased $0.4 million between periods primarily due to an increase in premiums related to our directors’ and officers’ insurance between periods.  Travel, meals and entertainment expenses increased $0.3 million between periods, primarily related to increased travel related to our sales team.  These increases were offset by a $0.5 million decrease in bad debt expense between periods.

Depreciation and amortization.   Depreciation and amortization increased by $0.9 million to $4.2 million in the six months ended June 30, 2008, from $3.3 million in the six months ended June 30, 2007. This increase was primarily related to the result of additional depreciation expense in the six months ended June 30, 2008 related to increased property and equipment balances between periods, primarily related to our expanded station network.

Interest income, net.   Interest income, net, increased by $0.3 million from $0.8 million in the six months ended June 30, 2007, to $1.1 million for the six months ended June 30, 2008. This increase was primarily the result of an increase in interest income in the six months ended June 30, 2008 due to higher average cash balances on hand associated with the proceeds received from our initial public offering in May 2007.

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Other income (expense), net.   Other income (expense), net, was $40,000 of income in the six months ended June 30, 2008, as compared to $179,000 of expense in the six months ended June 30, 2007. The increase was primarily related to the write-off of certain costs related to station relocation in the six months ended June 30, 2007 that did not occur in the first six months of 2008, and the sale of certain assets in the first six months of 2008 that did not occur in the first six months of 2007.

Equity in gains (losses) of equity method investee.      During the six months ended June 30, 2008, we recognized $140,000 of equity losses related to our joint venture in Peru. The CNG station owned by the joint venture opened in April 2008.

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 may also seek to acquire companies or assets in the natural gas fueling infrastructure, services and production industries.  We financed our operations in the first six months of 2008 primarily through cash on hand. At June 30, 2008, we had total cash and cash equivalents of $22.5 million compared to $67.9 million at December 31, 2007, and $8.5 million of short-term investments, compared to $12.5 million at December 31, 2007.

Cash used in operating activities was $12.9 million for the six months ended June 30, 2008, compared to cash provided by operating activities of $16.8 million for the six months ended June 30, 2007. The decrease in operating cash flow was primarily due to the change in certain deposits between periods. In January 2007, we received a refund of $22.9 million of margin deposits related to the transfer of certain futures contracts to Boone Pickens. Offsetting this increase were incremental deposits of $1.8 million we made related to the production of certain LNG trucks we anticipate will be operated in the Ports of Los Angeles and Long Beach and $1.2 million of margin deposits we made on our futures contracts in the first six months of 2008.

Cash used in investing activities was $32.6 million for the six months ended June 30, 2008, compared to $17.0 million for the six months ended June 30, 2007. The $15.6 million increase between periods was primarily due to increased purchases of property and equipment between periods.  Included in purchases of property and equipment in the first six months of 2008 was $26.8 million of construction costs related to our LNG liquefaction plant in California.  Offsetting this increase was the sale of $4.1 million of short-term investments during the six months ended June 30, 2008.

Cash provided by financing activities for the six months ended June 30, 2008 was $102,674, compared to $110.3 million for the six months ended June 30, 2007. In May 2007, we completed our initial public offering, which raised $110.3 million during the six month period ended June 30, 2007.

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

We intend to fund our principal liquidity requirements through cash and cash equivalents, cash provided by operations and through debt or equity financings. We anticipate we will need approximately $6.0 million of additional capital to fund our 2008 capital expenditure program in full. As reported in our Form 10-K for the year ended December 31, 2007 and filed with the SEC on March 19, 2008, we previously anticipated that we would need to raise approximately $40 million of additional capital during 2008 to fund our capital expenditure program in full. The decrease in our anticipated additional capital needs is primarily a result of accelerated collection of fuel tax credits, which the IRS now allows us to claim on a quarterly instead of annual basis, and lower projected costs for station construction activity during 2008 as a result of revised construction schedules. We may also seek to acquire companies or assets in the natural gas fueling infrastructure, services and production industries.  If we do so, we will need to raise additional capital as necessary to fund any such acquisitions as we did not contemplate any acquisitions in our 2008 capital expenditure plan. We may be unable to raise capital through equity or debt financing on favorable terms, or at all. If we are unable to obtain debt or equity financing in amounts sufficient to fund our 2008 capital

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expenditure program fully, or any proposed strategic transactions, we will be forced to suspend or curtail certain expansion projects or be unable to execute strategic transactions to acquire complementary companies or assets, which could harm our business, results of operations, or future prospects.

Capital Expenditures

We expect to make capital expenditures, net of grant proceeds, of approximately $95.6 million in 2008 to construct new natural gas fueling stations, to complete construction of our LNG liquefaction plant in California, and for general corporate purposes. Of the $95.6 million, we have budgeted approximately $49.9 million during 2008 to complete construction of our LNG liquefaction plant in California, which we anticipate will be operational in the fall of 2008. We also anticipate using approximately $4.2 million to finance the purchase of natural gas vehicles by our customers during 2008.

Contractual Obligations

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

(a)           Consists of obligations under a lease of capital equipment used to finance such equipment. Amounts do not include interest as the amounts are 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 three “take or pay” contracts. In October 2007, we entered into a 10-year contingent take-or-pay commitment for 45,000 LNG gallons per day from an LNG plant to be constructed in Arizona, which commitment is not reflected in the table above because of the contingent nature of the obligation. This obligation is contingent on the successful commencement of operations at the LNG plant.

(d)           Consists of our obligations to fund various fueling station construction projects, net of amounts funded through June 30, 2008, 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 and contracts we have entered into to acquire certain equipment and services related to the construction of our LNG plant in California. Amounts shown are net of amounts funded through June 30, 2008.

Off-Balance Sheet Arrangements

At June 30, 2008, we had the following off-balance sheet arrangements:

·                                          outstanding standby letters of credit totaling $685,000,

·                                          outstanding surety bonds for construction contracts and general corporate purposes totaling $8.4 million,

·                                          three take-or-pay contracts for the purchase of LNG,

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·                                          operating leases where we are the lessee,

·                                          capital leases where we are the lessor and owner of the equipment, and

·                                          firm commitments to sell CNG and LNG at fixed prices or index-plus prices subject to a price cap.

We provide standby letters of credit primarily to support facility leases and equipment purchases 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 for which we will not be reimbursed.

We have entered into contracts with three vendors to purchase LNG that require us to purchase minimum volumes from the vendors. One of the contracts expires in July 2008, one expires in December 2008, and the other contract expires in June 2011. The minimum commitments under these three contracts are included in the table set forth under “Take-or-pay” LNG purchase contracts above. On October 2007, we entered into a contingent take-or-pay contract from an LNG plant that is under construction that is not included in the table 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 building an LNG liquefaction plant. We have budgeted approximately $49.9 million in 2008 to finish construction of 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 million 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. 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 58% of our cost of sales for 2007 and 66% of our cost of sales for the six months ended June 30, 2008. Prices for natural gas over the eight-year and six-month period from December 31, 1999 through June 30, 2008, 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 June 30, 2008, the NYMEX index price of natural gas was $11.93 per Mcf.

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

We account for these futures contracts in accordance with SFAS 133. Under this standard, the accounting for changes in the fair value of a derivative depends upon whether it has been designated in a hedging relationship and, further, on the type of hedging relationship. To qualify for designation in a hedging relationship, specific criteria must be met and appropriate documentation maintained. Our futures contracts did not qualify for hedge accounting under SFAS 133 for the years ended December 31, 2005, 2006 and 2007 and for the six-month period ended June 30, 2008, and changes in the fair value of any derivatives we owned were recorded directly to our consolidated statements of operations at the end of each reporting period.

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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. 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.

We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to the futures contracts we still hold as of the date of this report to hedge the fixed-price component of the City of Phoenix LNG supply contract we were awarded.  If we fail to qualify the futures contracts as cash flow hedges under SFAS 133 and continue to hold them, and the price of natural gas were to fluctuate (increase or decrease) by 10% from the price quoted on NYMEX on June 30, 2008 ($11.93 per Mcf), we could expect a corresponding fluctuation in derivative (gains) losses of approximately $450,000.

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 June 30, 2008. 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:

This table does not include two 2.1 million LNG gallon per year renewal options that one of our customers possesses related to an LNG price cap contract.  Had the contract been included, assuming both renewal periods were exercised, the resulting amount for the price cap contracts would be $(1.1) million.

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Item 4. – Controls and Procedures

Not applicable

Item 4T. – Controls and Procedures

Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

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.

PART II. – OTHER INFORMATION

Item 1. – Legal Proceedings

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

Item 1A. – Risk Factors

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-K for the year ended December 31, 2007  (filed with the SEC on March 19, 2008) 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.

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We paid to the underwriters underwriting discounts totaling approximately $7.0 million in connection with the offering. In addition, we incurred additional costs of approximately $4.5 million of costs 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. 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 June 30, 2008, we have used the net proceeds from the offering as follows:

·                                          construction of our LNG liquefaction plant in California ($43.6 million),

·                                          construction and installation of CNG and LNG stations ($11.5 million),

·                                          financing customer vehicle purchases ($3.4 million), and

·                                          working capital ($16.3 million).

The balance of the proceeds has been invested in instruments that have financial maturities no longer than six months. We intend to use the remaining proceeds to finish building our LNG liquefaction plant in California, to build additional CNG and LNG fueling stations, to finance additional purchases of natural gas vehicles by our customers and for general corporate purposes, including making deposits to support our derivative activities, geographic expansion (domestically and internationally) and to expand our sales and marketing activities. We cannot specify with certainty all of the particular uses for the net proceeds from our initial public offering, and the amount and timing of our expenditures will depend on several factors. Accordingly, our management will have broad discretion in the application of the net proceeds.

Item 3. – Defaults upon Senior Securities

None.

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

On May 28, 2008, we held our Annual Meeting of Stockholders in Newport Beach, California. At the meeting, the stockholders elected management’s slate of directors and approved one additional proposal with the following vote distribution: