UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2008

Commission File Number: 001-33480

CLEAN ENERGY FUELS CORP.

(Exact name of registrant as specified in its charter)

Delaware		33-0968580
(State or other jurisdiction of incorporation)		(IRS Employer Identification No.)

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

(Address of principal executive offices, including zip code)

(562) 493-2804

(Registrants 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):

Large accelerated filer o		Accelerated filer o

Non-accelerated filer x		Smaller reporting company o
(Do not check if a smaller reporting company)

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

As of November 12, 2008, there were 50,195,471 shares of the registrants 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)	3

	Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations	16

	Item 3. Quantitative and Qualitative Disclosures About Market Risk	27

	Item 4. Controls and Procedures	28

	Item 4T. Controls and Procedures	28

PART II. - OTHER INFORMATION

	Item 1. Legal Proceedings	29

	Item 1A. Risk Factors	29

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	39

	Item 3. Defaults upon Senior Securities	39

	Item 4. Submission of Matters to a Vote of Security Holders	39

	Item 5. Other Information	40

	Item 6. Exhibits	41

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PART I.  FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Balance Sheets

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

	December 31, 2007			September 30, 2008

Assets
Current assets:
Cash and cash equivalents	$	67,937,602		$	30,392,856
Restricted cash				2,502,032
Short-term investments	12,479,684
Accounts receivable, net of allowance for doubtful accounts of $501,751 and $878,358 as of December 31, 2007 and September 30, 2008, respectively	11,026,890			12,943,373
Other receivables	23,153,904			11,793,587
Inventory, net	2,403,890			2,460,328
Deposits on LNG trucks	15,515,927			10,160,721
Prepaid expenses and other current assets	3,633,318			4,946,082
Total current assets	136,151,215			75,198,979

Land, property and equipment, net	88,676,318			142,169,616
Capital lease receivables	763,500			464,250
Notes receivable and other long-term assets	2,126,007			5,266,654
Investments in other entities	385,806			3,549,723
Goodwill and other intangible assets	20,922,098			42,042,604
Total assets	$	249,024,944		$	268,691,826

Liabilities and Stockholders Equity
Current liabilities:
Current portion of long-term debt and capital lease obligation	$	63,520		$	3,737,052
Accounts payable	10,547,451			9,291,037
Accrued liabilities	5,381,541			7,251,794
Deferred revenue	677,826			717,169
Total current liabilities	16,670,338			20,997,052

Long-term debt and capital lease obligation, less current portion	161,377			18,536,733
Other long-term liabilities	1,260,755			1,240,665
Total liabilities	18,092,470			40,774,450

Commitments and contingencies

Minority interest in subsidiary				3,744,671

Stockholders equity:
Preferred stock, $0.0001 par value. Authorized 1,000,000 shares; issued and outstanding no shares
Common stock, $0.0001 par value. Authorized 99,000,000 shares; issued and outstanding 44,274,375 shares and 44,641,520 shares at December 31, 2007 and September 30, 2008, respectively	4,428			4,463
Additional paid-in capital	297,866,745			310,899,518
Accumulated deficit	(69,086,583		)	(87,565,158		)
Accumulated other comprehensive income	2,147,884			833,882
Total stockholders equity	230,932,474			224,172,705
Total liabilities and stockholders equity	$	249,024,944		$	268,691,826

See accompanying notes to condensed consolidated financial statements.

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Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Statements of Operations

For the Three Months and Nine Months Ended

September 30, 2007 and 2008

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2008			2007			2008

Revenue	$	29,210,164		$	35,273,687		$	88,040,804		$	99,823,025
Operating expenses:
Cost of sales	20,252,744			26,111,054			64,100,466			77,138,760
Derivative losses				6,047,727						340,746
Selling, general and administrative	9,528,605			11,397,913			26,269,201			35,124,764
Depreciation and amortization	1,814,176			2,310,527			5,090,396			6,557,967
Total operating expenses	31,595,525			45,867,221			95,460,063			119,162,237
Operating loss	(2,385,361		)	(10,593,534		)	(7,419,259		)	(19,339,212		)

Interest income, net	1,414,120			78,399			2,253,083			1,182,962
Other income (expense), net	(50,000		)	(28,801		)	(229,177		)	11,177
Equity in gains (losses) of equity method investee				19,881						(120,441		)
Loss before income taxes	(1,021,241		)	(10,524,055		)	(5,395,353		)	(18,265,514		)
Income tax expense	(523,729		)	(99,171		)	(582,698		)	(199,141		)
Minority interest in net income				(13,920		)				(13,920		)
Net loss	$	(1,544,970	)	$	(10,637,146	)	$	(5,978,051	)	$	(18,478,575	)

Loss per share
Basic	$	(0.03	)	$	(0.24	)	$	(0.15	)	$	(0.42	)
Diluted	$	(0.03	)	$	(0.24	)	$	(0.15	)	$	(0.42	)

Weighted average common shares outstanding
Basic	44,195,339			44,330,818			38,919,129			44,304,636
Diluted	44,195,339			44,330,818			38,919,129			44,304,636

See accompanying notes to condensed consolidated financial statements.

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Clean Energy Fuels Corp.

Condensed Consolidated Statements of Cash Flows

For the Nine Months Ended September 30, 2007 and 2008

(Unaudited)

	Nine Months Ended September 30,
	2007			2008
Cash flows from operating activities:
Net loss	$	(5,978,051	)	$	(18,478,575	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization	5,090,396			6,557,967
Provision for doubtful accounts	1,179,600			410,906
Gain (loss) on disposal of assets	178,674			(9,555		)
Stock option expense	5,425,443			7,782,538
Common stock issued in exchange for services				22,500
Minority interest in net income				13,920
Changes in operating assets and liabilities, net of assets and liabilities acquired:
Accounts and other receivables	9,099,031			9,989,396
Inventory	(1,221,776		)	(56,438		)
Deposits on LNG trucks	(7,928,016		)	5,355,206
Margin deposits on futures contracts				(754,256		)
Capital lease receivables	549,250			299,250
Prepaid expenses and other assets	(1,508,219		)	(3,559,283		)
Accounts payable	1,269,128			(561,936		)
Accrued expenses and other	2,479,123			823,710
Net cash provided by operating activities	8,634,583			7,835,350

Cash flows from investing activities:
Purchases of property and equipment	(29,874,682		)	(59,828,850		)
Proceeds from sale of property and equipment				48,432
Purchases of short-term investments	(14,809,636		)	(45,230,061		)
Maturity or sales of short-term investments				57,709,745
Acquisition, net of cash acquired				(19,615,122		)
Investments in other entities	(377,855		)	(3,238,866		)
Restricted cash				(2,502,032		)
Net cash used in investing activities	(45,062,173		)	(72,656,754		)

Cash flows from financing activities:
Proceeds from issuance of common stock and exercise of stock options	110,301,745			5,227,770
Proceeds from long-term debt				22,124,120
Repayment of capital lease obligations and long-term debt	(42,583		)	(75,232		)
Net cash provided by financing activities	110,259,162			27,276,658

Net increase (decrease) in cash	73,831,572			(37,544,746		)
Cash, beginning of period	937,445			67,937,602
Cash, end of period	$	74,769,017		$	30,392,856

Supplemental disclosure of cash flow information
Income taxes paid	$	250		$	164,779
Interest paid	80,749			129,646

See accompanying notes to condensed consolidated financial statements.

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 General

Nature of Business: Clean Energy Fuels Corp. (the Company) is engaged in the business of selling natural gas fueling solutions to its customers primarily in the United States and Canada. The Company has a broad customer base in a variety of markets including public transit, refuse, airports and regional trucking. Clean Energy operates or supplies approximately 175 natural gas fueling locations in California, Texas, Colorado, Maryland, New York, New Mexico, Nevada, Washington, Massachusetts, Georgia, Wyoming, Arizona, Ohio, and Alabama within the United States, and in British Columbia and Ontario within Canada. The Company also generates revenue through operation and maintenance agreements with certain customers, through building and selling or leasing natural gas fueling stations to its customers, and through financing its customers vehicle purchases. In April 2008, the Company opened its first compressed natural gas (CNG) station in Lima, Peru through the Companys joint venture, Clean Energy del Peru. In August 2008, the Company acquired 70% of the outstanding membership interests of Dallas Clean Energy, LLC (DCE). DCE owns a facility that collects, processes and sells landfill gas in Texas.

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

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

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

Note 2  Acquisition

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

The Company paid an aggregate of $19.1 million to acquire a 70% interest in DCE. Of the purchase price, $1.0 million was deposited into a third-party escrow as security for indemnification claims. The amount remaining in the escrow will be released to the sellers on August 15, 2009, except for amounts subject to pending indemnification claims, if any.

The Company borrowed $18.0 million from PlainsCapital Bank to finance its acquisition of its membership interests in DCE. The Company also obtained a $12.0 million line of credit from PlainsCapital Bank to finance capital improvements of the DCE processing facility pursuant to a loan made by the Company to DCE and to pay certain costs and expenses related to the acquisition and the PlainsCapital Bank loan. As of September 30, 2008, the Company had borrowed $4.2 million under the line of credit (see note 11).

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

Current assets	$	1,129,389
Property, plant and equipment	1,821,770
Identifiable intangible assets	21,341,906
Total assets acquired	24,293,065

Current liabilities assumed	(1,480,770		)
Minority interest	(3,730,751		)

Total purchase price	$	19,081,544

Management preliminarily allocated approximately $21.3 million to the identifiable intangible asset related to the fair value of DCEs landfill lease with the City of Dallas that was acquired with the acquisition. The fair value of the identifiable intangible asset will be amortized on a straight-line basis over the remaining life of the lease, approximately 16.5 years at the acquisition date.

The results of DCEs operations have been included in the Companys consolidated financial statements since August 15, 2008. The pro-forma effect of the acquisition is not material to the Companys results of operations for the year ended December 31, 2007 and the first nine months of 2008.

Note 3  Cash and Cash Equivalents

The Company considers all highly liquid investments with maturities of three months or less on the date of acquisition to be cash equivalents. Cash and cash equivalents generally consist of cash, time deposits, commercial paper, money market funds and government and corporate debt securities with original maturity dates of three months or less. Such investments are stated at cost, which approximates fair value.

Note 4  Short-Term Investments

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

Note 5 Derivative Financial Instruments

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

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The Company marks to market its open futures position at the end of each period and records the net unrealized gain or loss during the period in derivative (gains) losses in the consolidated statements of operations or in accumulated other comprehensive income in the condensed consolidated balance sheets in accordance with the provisions of SFAS 133. For the three and nine month periods ended September 30, 2008, the Company recorded losses of $6.0 million and $0.3 million, respectively, related to its futures contracts in the consolidated statements of operations. These futures contracts were related to the portion of an LNG supply contract that the Company bid on but was not awarded. The Company recorded unrealized losses of $1.1 million in accumulated other comprehensive income for the three months ended September 30, 2008 for the futures contracts applicable to the portion of the LNG supply contract it was awarded (see note 6). The liability for these contracts is in accrued liabilities on the Companys condensed consolidated balance sheet at September 30, 2008. There was no ineffectiveness of the futures contracts recognized during the period. The Company recognized losses of $0.2 million during the three and nine month periods ended September 30, 2008 related to futures contracts applicable to this supply contract. Such amounts are included in cost of sales in the condensed consolidated statements of operations.

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

Note 6 Fixed Price and Price Cap Sales Contracts

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

As part of determining the fixed price or price cap in the contracts, the Company works with its customers to determine their future usage over the contract term. However, the Companys 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 Companys 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 customers contract price and the corresponding index price of natural gas typically develops after the Company enters into the sales contract (with the price of natural gas having historically increased). From time to time, the Company has also entered into natural gas futures contracts to offset economically the adverse impact of rising natural gas prices (see note 5) and, if the Company believed the price of natural gas would decline in the future, periodically sold such contracts.

From an accounting perspective, during periods of rising natural gas prices, the Companys 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 Companys 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 Companys statements of operations during this historical period of rising natural gas prices for the future commitments under these contracts. As a result, the Companys statements of operations do not reflect its firm commitments to deliver LNG or CNG at prices that are below, and in some cases, substantially below, the prevailing market price of natural gas (and therefore LNG or CNG).

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

	Estimated volumes (a)	Average price (b)		Contracts duration
CNG fixed price contracts	1,207,617	$	1.17	through 12/13
LNG fixed price contracts	2,536,371	$	0.51	through 07/09
CNG price cap contracts	2,253,804	$	0.83	through 12/09
LNG price cap contracts	1,050,000	$	0.62	through 03/09

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

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

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

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

October 1, 2008 through December 31, 2008		2,062,785
2009		2,831,296
2010		230,000
2011		230,000
2012		230,000
2013		230,000

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 Companys 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 Companys Form 8-K dated June 19, 2008, the supply contract for which the futures contracts were purchased was awarded to a competitor of the Company. The Company protested the award of the contract to its competitor and ultimately the Company was awarded a portion of the contract representing approximately one-third of the contract volumes. In July 2008, the Company then sold the futures contracts related to the portion of the contract it was not awarded. Due to the decrease in the price of natural gas between the date the futures contracts were purchased and the date they were sold, the Company ultimately realized a net loss of $0.3 million related to the sale of the futures contracts purchased with respect to the portion of the fixed-price contract that was not awarded to the Company. The remaining futures contracts qualify for hedge accounting as cash flow hedges under SFAS 133 (see note 5).

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Note 7 Other Receivables

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

	December 31, 2007		September 30, 2008

Loans to customers to finance vehicle purchases	$	1,393,549	$	1,906,777
Advances to vehicle manufacturers	4,871,373		2,903,707
Fuel tax credits	14,920,145		5,532,061
Other	1,968,837		1,451,042
	$	23,153,904	$	11,793,587

Note 8 Land, Property and Equipment

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

	December 31, 2007			September 30, 2008
Land	$	472,616		$	472,616
LNG liquefaction plant	12,898,178			12,921,046
Station equipment	48,318,709			52,442,945
LNG tanker trailers	11,698,145			11,793,681
Other equipment	6,937,083			10,524,396
Construction in progress	32,297,191			84,066,532
	112,621,922			172,221,216
Less accumulated depreciation	(23,945,604		)	(30,051,600		)
	$	88,676,318		$	142,169,616

Note 9 Investments in Other Entities

In August 2008, the Company invested approximately $3.2 million in The Vehicle Production Group LLC (VPG), a company that is developing a natural gas vehicle made in the United States for taxi and paratransit use. The Company committed to fund up to $10 million in VPG from August 2008 through March 2010. $7.5 million is a firm commitment by the Company, and $2.5 million is contingent on VPG not being able to raise money on more-favorable terms than the funding from the original investor group. The Company accounts for its investment in VPG under the cost method of accounting as the Company does not have the ability to exercise significant influence over VPGs operations.

On August 27, 2008, a subsidiary of the Company converted outstanding commercial loans previously made to Bachman NGV, Inc. (BAF), a natural gas vehicle conversion company, into a secured convertible promissory note (the Note) that is convertible into equity interests in BAF. The Note is convertible at the Companys option after August 27, 2009 and may be converted earlier upon an acquisition of BAF. As of September 30, 2008, the $3.6 million outstanding under the Note would convert into approximately 47% of the outstanding equity interests of BAF if fully converted. The Company may, at the Companys discretion, advance up to $2.4 million in additional funds to BAF under the Note. The Note bears interest at 5% per annum and is due August 30, 2010.

Note 10 Accrued Liabilities

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

	December 31, 2007		September 30, 2008
Salaries and wages	$	1,495,196	$	1,008,327
Accrued gas purchases	1,840,358		1,820,241
Obligation under derivative liability			1,065,797
Accrued employee benefits	317,798		804,953
Other	1,728,189		2,552,476
	$	5,381,541	$	7,251,794

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Note 11 Long-term Debt

In conjunction with the Companys acquisition of its 70% interest in DCE (see note 2), on August 15, 2008, the Company entered into a Credit Agreement with PlainsCapital Bank. The Company borrowed $18.0 million (the Facility A Loan) to finance the acquisition of its membership interests in DCE. The Company also obtained a $12.0 million line of credit from PlainsCapital Bank to finance capital improvements of the DCE processing facility and to pay certain costs and expenses related to the acquisition and the PlainsCapital Bank loans (the Facility B Loan). As of September 30, 2008, the Company had borrowed $4.2 million under the Facility B Loan. The Company may request funds up to $12.0 million under the Facility B Loan through February 15, 2009. Interest accrues daily on the Facility A and B Loans at the greater of the prime rate of interest for the United States plus 0.50% per annum or 5.50% per annum. The Company paid a facility fee of $300,000 in connection with the Credit Agreement. As of September 30, 2008, the unamortized balance of the facility fee was $292,500. Amortization of the facility fee is recorded as additional interest expense in the consolidated statements of operations.

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

Interest on the unpaid principal balance of the Facility B Loans is due and payable quarterly commencing on September 30, 2008. The principal amount of the Facility B Loans is due and payable in annual payments commencing on August 1, 2009, and continuing each anniversary date thereafter, with each such payment being in an amount equal to the lesser of the aggregate principal amount of the Facility B Loan then outstanding or $2,800,000. On August 15, 2013, the remaining amount of unpaid principal and interest under the Facility B Loans is due and payable.

The Credit Agreement requires the Company to comply with certain covenants. The Company may not incur indebtedness or liens except as permitted by the Credit Agreement, or declare or pay dividends. The Company must maintain minimum liquidity of not less than $6.0 million at each quarter end beginning December 31, 2008, maintain an accounts receivable balance, as defined, at each month end of not less than $10.0 million beginning August 31, 2008, maintain consolidated net worth, as defined, of not less than $150.0 million and a debt to equity ratio, as defined, of not more than 0.3 to 1 at each quarter end beginning September 30, 2008, and a debt service ratio, as defined, of not less than 1.5 to 1 for each quarterly period beginning June 30, 2009. If the Company defaults on the Credit Agreement, all of the obligations under the Credit Agreement will become immediately due and payable.

The Credit Agreement is secured by the Companys interest in, and note receivable from, DCE (described below), certain of the Companys accounts receivable and inventory balances and 45 of the Companys LNG tanker trailers.

As part of the transaction, the Company also entered into a Loan Agreement with DCE (the DCE Loan) to provide secured financing of up to $14.0 million to DCE for future capital expenditures. Upon closing of the acquisition of DCE, the Company funded approximately $714,000 under the agreement. The funds were obtained as part of the initial $4.2 million funded under the Facility B Loan with PlainsCapital Bank to the Company. Interest on the unpaid balance accrues at a rate of 12% per annum and is payable quarterly beginning September 30, 2008. The principal amount of the loan is due and payable in annual payments commencing on August 1, 2009, and continuing each anniversary date thereafter, with each such payment being in an amount equal to the lesser of the aggregate principal amount of the DCE Loan then outstanding or $2,800,000. On August 1, 2013, the entire amount of unpaid principal and interest under the DCE Loan is due and payable. The principal and accrued interest balances as well as any interest income related to the DCE Loan are eliminated in the consolidated financial statements of the Company. Any event of default by DCE on the DCE Loan results in a cross-default of the Companys Credit Agreement with PlainsCapital Bank. Events of default include failure to make payments when due, DCEs failure to perform under the provisions of its landfill lease with the City of Dallas, DCEs violation of a covenant under its operating agreement and other standard events of default.

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

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

	Facility A Loan		Facility B Loan		Capital Lease		Total
2009	$	868,607	$	2,800,000	$	68,445	$	3,737,052
2010	918,301		1,364,549		75,613		2,358,463
2011	970,838				33,797		1,004,635
2012	1,024,062						1,024,062
2013	14,149,573						14,149,573

Total	$	17,931,381	$	4,164,549	$	177,855	$	22,273,785

Note 12 Issuance of Common Stock

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

Note 13 Earnings Per Share

Basic earnings per share is based upon the weighted average number of shares outstanding during each period. Diluted earnings per share reflects the impact of assumed exercise of dilutive stock options and warrants. The information required to compute basic and diluted earnings per share is as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2007	2008	2007	2008

Basic and diluted:
Weighted average number of common shares outstanding	44,195,339	44,330,818	38,919,129	44,304,636

Certain securities were excluded from the diluted earnings per share calculations at September 30, 2007 and 2008, respectively, as the inclusion of the securities would be anti-dilutive to the calculation. The amounts outstanding as of September 30, 2007 and 2008 for these instruments are as follows:

	September 30,
	2007	2008

Options	5,720,666	7,018,955
Warrants	15,000,000	15,000,000

Note 14 Comprehensive Income (Loss)

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

	Nine Months Ended September 30,
	2007			2008
Net loss	$	(5,978,051	)	$	(18,478,575	)
Derivative unrealized losses				(1,065,797		)
Foreign currency translation adjustments	663,665			(248,205		)

Comprehensive loss	$	(5,314,386	)	$	(19,792,577	)

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Note 15 Stock-Based Compensation

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2008		2007		2008

Stock options:
Stock-based compensation expense	$	1,592,789	$	2,684,207	$	5,425,443	$	7,782,538
Income tax benefit
Stock-based compensation expense, net of tax	$	1,592,789	$	2,684,207	$	5,425,443	$	7,782,538

Stock Options

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

	Number of Shares		Weighted- Average Exercise Price

Outstanding at December 31, 2007	6,553,036		$	9.37
Granted	616,000		15.86
Exercised	(45,914	)	4.96
Cancelled/Forfeited	(104,167	)	13.97
Outstanding at September 30, 2008	7,018,955		9.88

Exercisable at September 30, 2008	3,375,787		5.93

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:

	Nine months Ended September 30, 2008

Dividend yield	0.00	%
Expected volatility	54.67	%
Risk-free interest rate	2.93	%
Expected life in years	6.00

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

Note 16 Use of Estimates

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

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Note 17 Environmental Matters, Litigation, Claims, Commitments and Contingencies

The Company is subject to federal, state, local, and foreign environmental laws and regulations. The Company does not anticipate any expenditures to comply with such laws and regulations which would have a material impact on the Companys 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 Companys 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 Companys consolidated financial position, results of operations, or liquidity.

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

Note 18 Income Taxes

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

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

Note 19 Recently Adopted Accounting Changes

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

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

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

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

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

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

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

	Balance at September 30, 2008		Quoted Prices In Active Markets for Identical Items (Level 1)	Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Natural gas futures contracts obligation	$	1,065,797	$	$	1,065,797	$

Note 20 Subsequent Events

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

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

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

Issuance of Common Stock and Warrants  On October 28, 2008, the Company entered into a Placement Agent Agreement (the Placement Agent Agreement) relating to the sale and issuance by the Company to select investors of up to 4,419,192 units (the Units), with each Unit consisting of (i) one share of the Companys common stock, par value $0.0001 per share, (ii) a warrant to purchase 0.75 shares of Common Stock (the Series I Warrant), and (iii) one warrant to purchase up to 0.2571 shares of Common Stock (the Series II Warrant). The price of each Unit was $7.92 per Unit. The transaction closed on November 3, 2008 and the Company issued 4,419,192 shares of common stock, Series I Warrants to purchase up to 3,314,394 shares of Common Stock, and Series II Warrants to purchase up to 1,136,364 shares of Common Stock. The Company received approximately $32.5 million after deducting the placement agents fees and other offering expenses.

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

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

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Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations.

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

We provide natural gas solutions for vehicle fleets primarily in the United States and Canada. In April 2008, we opened our first CNG station in Lima, Peru, through our joint venture, Clean Energy del Peru. Our primary business activity is selling CNG and LNG vehicle fuels to our customers. We also build, operate and maintain fueling stations, and help our customers acquire and finance natural gas vehicles and obtain local, state and federal clean air incentives. Our customers include fleet operators in a variety of markets, such as public transit, refuse hauling, airports, taxis and regional trucking. In August 2008, we acquired 70% of the outstanding membership interest of Dallas Clean Energy, LLC (DCE). DCE owns a facility that collects, processes and sells landfill gas at the McCommas Bluff landfill located in Dallas, Texas.

Overview

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

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

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

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Gasoline gallon equivalents delivered (in millions)	Year Ended December 31, 2005	Year Ended December 31, 2006	Year Ended December 31, 2007	Three Months Ended September 30, 2007	Nine Months Ended September 30, 2007	Three Months Ended September 30, 2008	Nine Months Ended September 30, 2008
CNG	36.1	41.9	48.0	12.9	36.3	12.9	36.3
LNG	20.7	26.5	27.3	7.1	20.8	5.8	18.5

Total	56.8	68.4	75.3	20.0	57.1	18.7	54.8

Operating data
Revenue	$	77,955,083	$	91,547,316		$	117,716,233		$	29,210,164		$	88,040,804		$	35,273,687		$	99,823,025
Net income (loss)	17,257,587		(77,500,741		)	(8,894,362		)	(1,544,970		)	(5,978,051		)	(10,637,146		)	(18,478,575		)

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

The number of fueling stations we served grew from 147 at December 31, 2004 to 175 at September 30, 2008 (a 19.0% increase). The amount of CNG and LNG gasoline gallon equivalents we delivered from 2005 to 2007 increased by 32.6%. Our cost of sales also increased during these periods, which was attributable primarily to the increased price of natural gas and increased costs related to delivering CNG and LNG to our customers.

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

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

Anticipated future trends. We anticipate that, over the long term, the prices for gasoline and diesel will continue to be higher than the price of natural gas as a vehicle fuel, and more stringent emissions requirements will continue to make natural gas vehicles an attractive alternative to traditional gasoline and diesel powered vehicles. We believe there will be significant growth in the consumption of natural gas as a vehicle fuel among vehicle fleets, and our goal is to capitalize on this trend and enhance our leadership position as this market expands. We have built a natural gas fueling station, and plan to build additional natural gas fueling stations, that will provide LNG to fleet vehicles at the Ports of Los Angeles and Long Beach. We also anticipate expanding our sales of CNG and LNG in the other markets in which we operate, including public transit, refuse hauling and airports. Consistent with the anticipated growth of our business, we also expect that our operating costs and capital expenditures will increase, primarily from the logistics of delivering more CNG and LNG to our customers, as well as from the anticipated expansion of our station network. We also continue to incur significant costs related to the LNG liquefaction plant we are in the process of building in California. Additionally, we have and will continue to increase our sales and marketing team and other necessary personnel as we seek to expand our existing markets and enter new markets, which will also result in increased costs.

Sources of liquidity and anticipated capital expenditures. In May 2007, we completed our initial public offering of 10,000,000 shares of common stock at a public offering price of $12.00 per share. Net cash proceeds from the initial public offering were approximately $108.5 million, after deducting underwriting discounts, commissions and offering expenses. Historically, our principal sources of liquidity have been cash provided by operations, capital contributions from our stockholders, our cash and cash equivalents and, during the third and fourth quarters of fiscal 2006, a revolving line of credit with Boone Pickens, a director and our largest stockholder. The line of credit was used to fund margin requirements on certain derivative contracts and was terminated in December 2006. On September 24, 2008, we sold 319,488 shares of our common stock at a purchase price of $15.65 per share to Boone Pickens Interests, Ltd. for proceeds of approximately $5.0 million. On November 3, 2008 we sold 4,419,192 shares of common stock and warrants exercisable for common stock and received net proceeds of approximately $32.5 million. (See note 20 to the accompanying condensed consolidated financial statements for a discussion of the transaction). After this transaction, we had approximately $38.5 million in total cash and cash equivalents.

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

Volatility in operating results related to futures contracts. Historically, we have purchased futures contracts from time to time to help mitigate our exposure to natural gas price fluctuations in current periods and in future periods. Gains and losses related to our futures activities, which appear in the line item derivative (gains) losses in our condensed consolidated financial statements, have materially impacted our results of operations in recent periods. For the years ended December 31, 2005, 2006 and 2007, derivative (gains) losses were $(44,067,744), $78,994,947, and $0, respectively. For the nine months ended September 30, 2007 and 2008, derivative (gains) losses were $0 and $340,746, respectively. For this reason and others, we caution investors that our past operating results may not be indicative of future results. For more information, please read Volatility of Earnings and Cash Flows and Risk Management Activities below.

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

Operations

We generate revenues principally by selling CNG and LNG to our vehicle fleet customers. For the nine months ended September 30, 2008, CNG represented 66% and LNG represented 34% of our natural gas sales (on a gasoline gallon equivalent basis). To a lesser extent, we generate revenues by operating and maintaining natural gas fueling stations that are owned either by us or our customers and selling landfill gas provided by our interest in DCE (commencing in August 2008). Substantially all of our operating and maintenance revenues are generated from CNG stations, as owners of LNG stations tend to operate and maintain their own stations. In addition, we generate a small portion of our revenues by designing and constructing fueling stations and selling or leasing those stations to our customers. Substantially all of our station sale and leasing revenues have been generated from CNG stations. In 2006, we began providing vehicle finance services to our customers.

CNG Sales

We sell CNG through fueling stations located on our customers properties and through our network of public access fueling stations. At these CNG fueling stations, we procure natural gas from local utilities or brokers under standard, floating-rate arrangements and then compress and dispense it into our customers vehicles. Our CNG sales are made primarily through contracts with our fleet customers. Under these contracts, pricing is determined primarily on an index-plus basis, which is calculated by adding a margin to the local index or utility price for natural gas. We sell a small amount of CNG under fixed-price contracts and also provide price caps to certain customers on their index-plus pricing arrangement. Effective January 1, 2007, we no longer intend to offer price-cap contracts to our customers, but we will continue to perform our obligations under price-cap contracts we entered into before January 1, 2007. We will continue to offer fixed price contracts as appropriate and consistent with our revised natural gas hedging policy revised in May 2008. Our fleet customers typically are billed monthly based on the volume of CNG sold at a station. The remainder of our CNG sales are on a per fill-up basis at prices we set at the pump based on prevailing market conditions. These customers typically pay using a credit card at the station. In April 2008, we opened our first CNG station in Lima, Peru through our joint venture Clean Energy del Peru.

LNG Sales

We sell substantially all of our LNG to fleet customers, who typically own and operate their fueling stations. We also sell a small volume of LNG to customers for non-vehicle use. We procure LNG from third-party producers and also produce LNG at our liquefaction plant in Texas. For LNG that we purchase from third-parties, we typically enter into take or pay contracts that require us to purchase minimum volumes of LNG at index-based rates. We deliver LNG via our fleet of 60 tanker trailers to fueling stations, where it is stored and dispensed in liquid form into vehicles. We sell LNG principally through supply contracts that are priced on either a fixed-price or index-plus basis. We also provided price caps to certain customers on the index component of their index-plus pricing arrangement for certain contracts we entered into on or prior to December 31, 2006. Effective January 1, 2007, we no longer intend to offer price-cap contracts to our customers, but we will continue to perform our obligations under price-cap contracts we

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entered into before January 1, 2007, including two one-year renewal periods beginning April 1, 2009 that one of our customers is entitled to should they choose to exercise such renewals. The renewal periods, if exercised, would obligate us to sell the customer approximately 2.1 million LNG gallons on an annual basis subject to a price cap of $7.50 per MMbtu on the SoCal Border index for each renewal year. We will continue to offer fixed price contracts as appropriate and consistent with our revised natural gas hedging policy adopted in May 2008. Our LNG contracts provide that we charge our customers periodically based on the volume of LNG supplied.

Government Incentives

From October 1, 2006 through December 31, 2009, we may receive a Volumetric Excise Tax Credit (VETC) of $0.50 per gasoline gallon equivalent of CNG and $0.50 per liquid gallon of LNG that we sell as vehicle fuel. Based on the service relationship we have with our customers, either we or our customers are able to claim the credit. We expect the tax credit will continue to factor into the price we charge our customers for CNG and LNG in the future. The legislation that created this tax credit also increased the federal excise taxes on sales of CNG from $0.061 to $0.183 per gasoline gallon equivalent and on sales of LNG from $0.119 to $0.243 per LNG gallon. These new excise tax rates are approximately the same as those for gasoline and diesel fuel.

Operation and Maintenance

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

Station Construction

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

Vehicle Acquisition and Finance

In 2006, we commenced offering vehicle finance services for some of our customers purchases of natural gas vehicles or the conversion of their existing gasoline or diesel powered vehicles to operate on natural gas. We loan to our customers up to 100% of the purchase price of their natural gas vehicles. We may also lease vehicles in the future. Where appropriate, we apply for and receive state and federal incentives associated with natural gas vehicle purchases and pass these benefits through to our customers. We may also secure vehicles to place with customers or pay deposits with respect to such vehicles prior to receiving a firm order from our customers, which we may be required to purchase if our customer fails to purchase the vehicle as anticipated. As of September 30, 2008, we have not generated significant revenue from vehicle finance activities.

Landfill Gas

In August 2008, we acquired 70% of the outstanding membership interests of DCE. DCE owns a facility that collects, processes and sells landfill gas at the McCommas Bluff landfill located in Dallas, Texas. A small portion of our revenues are derived from our interest in DCE.

Volatility of Earnings and Cash Flows

Our earnings and cash flows historically have fluctuated significantly from period to period based on our futures activities, as all but a few of our futures contracts have not historically qualified for hedge accounting under SFAS 133. See Critical Accounting Policies below. We have therefore recorded any changes in the fair market value of these contracts directly in our statements of operations in the line item derivative (gains) losses along with any realized gains or losses generated during the period. For example, we experienced derivative gains of $33.1 million and $5.7 million for the three months ended September 30, 2005 and June 30, 2008, and derivative losses of $19.9 million, $0.3 million, $65.0 million, $13.7 million and $6.0 million for the three months ended December 31, 2005, March 31, 2006, September 30, 2006, December 31, 2006 and September 30, 2008,

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respectively. We had no derivative gains or losses for the three months ended June 30, 2006, March 31, 2007, June 30, 2007, September 30, 2007, December 31, 2007 and March 31, 2008.

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

Additionally, we are required to maintain a margin account to cover losses related to our natural gas futures contacts. Futures contracts are valued daily, and if our contracts are in loss positions at the end of a trading day, our broker will transfer the amount of the losses from our margin account to a clearinghouse. If at any time the funds in our margin account drop below a specified maintenance level, our broker will issue a margin call that requires us to restore the balance. Consequently, these payments could significantly impact our cash balances. At September 30, 2008, we had $0.8 million on deposit in margin accounts.

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

Risk Management Activities

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

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

Critical Accounting Policies

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

Recently Issued Accounting Pronouncements

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

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

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

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

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

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of SFAS 133 (SFAS 161). SFAS 161 requires disclosures of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entitys 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 SECs approval of the Public Company Accounting Oversight Board amendments to AU 411, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles. We do not expect the adoption of SFAS 162 will have a material impact on our results of operations and financial condition.

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Results of Operations

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2008		2007		2008
Statement of Operations Data::
Revenue	100.0	%	100.0	%	100.0	%	100.0	%
Operating expenses:
Cost of sales	69.3		74.0		72.8		77.3
Derivative (gains) losses			17.1				0.3
Selling, general and administrative	32.6		32.3		29.8		35.2
Depreciation and amortization	6.2		6.6		5.8		6.6
Total operating expenses	108.1		130.0		108.4		119.4
Operating loss	(8.2	)	(30.0	)	(8.4	)	(19.4	)

Interest income, net	4.8		0.2		2.6		1.2
Other income (expense), net	(0.2	)	(0.1	)	(0.3	)	0.0
Equity in gains (losses) of equity method investee			0.1				(0.1	)
Loss before income taxes	(3.5	)	(29.8	)	(6.1	)	(18.3	)
Income tax expense	(1.8	)	(0.3	)	(0.7	)	(0.2	)
Minority interest in net income			(0.0	)			(0.0	)
Net loss	(5.3	)	(30.2	)	(6.8	)	(18.5	)

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

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

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

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

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

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

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

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

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

Minority interest in net income. During the three months ended September 30, 2008, we recorded $14,000 for the minority interest in the net income of DCE. The minority interest represents the 30% interest of our joint venture partner. The results of DCEs operations have been included in the consolidated financial statements since August 15, 2008, the date of acquisition.

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

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

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

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

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

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

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

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

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

Minority interest in net income. During the nine months ended September 30, 2008, we recorded $14,000 for the minority interest in the net income of DCE. The minority interest represents the 30% interest of our joint venture partner. The results of DCEs operations have been included in the consolidated financial statements since August 15, 2008, the date of acquisition.

Liquidity and Capital Resources

Historically, our principal sources of liquidity have consisted of cash provided by operations and financing activities, cash and cash equivalents, the issuance of common stock, sometimes in association with the exercise of certain warrants that were callable at our option, and in 2006 a revolving line of credit with Boone Pickens, our majority stockholder. In May 2007, we completed our initial public offering of 10,000,000 shares of common stock at a public offering price of $12.00 per share. Net cash proceeds from the initial public offering were approximately $108.5 million, after deducting underwriting discounts, commissions and offering expenses. On August 15, 2008, in connection with our acquisition of 70% of the membership interests of DCE, we entered into a credit agreement with PlainsCapital Bank pursuant to which we borrowed $18.0 million under a term loan and an additional $4.2 million (as of September 30, 2008) under a line of credit (see note 11 to the accompanying condensed consolidated financial statements). On September 24, 2008, we sold 319,488 shares of our common stock at a price of $15.65 per share to Boone Pickens Interests, Ltd. for proceeds of approximately $5.0 million. On November 3, 2008 we sold 4,419,192 units of common stock and warrants for $7.92 per unit (See note 20 to the accompanying condensed consolidated financial statements for a discussion of the transaction) and we raised net proceeds of approximately $32.5 million after deducting offering costs.

In addition to funding operations, our principal uses of cash have been, and are expected to be, the construction of new fueling stations, the construction of a new LNG liquefaction plant in California, the purchase of new LNG tanker trailers, the financing of natural gas vehicles for our customers, and general corporate purposes, including making deposits to support our derivative activities, geographic expansion (domestically and internationally), expanding our sales and marketing activities,

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our support for Proposition 10 and for working capital for our expansion. We may also seek to acquire companies or assets in the natural gas fueling infrastructure, services and production industries. We financed our operations in the first nine months of 2008 primarily through cash on hand.

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

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

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

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

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

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

Capital Expenditures

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

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Contractual Obligations

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

	Payments Due by Period
Contractual Obligations:	Total		Remainder of 2008		2009 and 2010		2011 through 2013		2014 and beyond
Long-term debt and capital lease obligations (a)	$	26,863,390	$	540,929	$	6,826,359	$	19,496,102	$
Operating lease commitments (b)	10,405,454		431,868		3,413,464		4,594,567		1,965,555
Take-or-pay LNG purchase contracts (c)	8,343,000		2,455,500		4,890,000		997,500
Construction contracts (d)	14,899,898		14,899,898
Other long-term contract liabilities (e)	9,944,393		9,944,393

Total	$	70,456,135	$	28,272,588	$	15,129,823	$	25,088,169	$	1,965,555

(a) Consists of long-term debt and capital lease obligations under a lease of capital equipment used to finance such equipment.

(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 September 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 September 30, 2008.

Off-Balance Sheet Arrangements

At September 30, 2008, 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 $9.5 million,

· three 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 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.

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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 December 2008, one expires in March 2009 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. In 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 64% of our cost of sales for the nine months ended September 30, 2008. Prices for natural gas over the eight-year and nine-month period from December 31, 1999 through September 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 September 30, 2008, the NYMEX index price of natural gas was $8.40 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. Historically, our derivative instruments have not qualified for hedge accounting under SFAS 133. We did not have any derivative instruments during the year ended December 31, 2007, and had certain derivative instruments at September 30, 2008 to hedge a fixed-price LNG supply contract with a customer that did qualify for hedge accounting.

The fair value of the futures contracts we use is based on quoted prices in active exchange traded or over the counter markets. The fair value of these futures contracts is continually subject to change due to changing market conditions. In an effort to mitigate the volatility in our earnings related to futures activities, in February 2007, our board of directors adopted a revised natural gas hedging policy which restricts our ability to purchase natural gas futures contracts and offer fixed-price sales contracts to our customers. This policy was further revised by our board of directors in May 2008. We plan to structure prospective futures contracts so that they will be accounted for as cash flow hedges under SFAS 133, but we cannot be certain they will qualify.

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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 portion of the City of Phoenix LNG supply contract we were awarded. If the price of natural gas were to fluctuate (increase or decrease) by 10% from the price quoted on NYMEX on September 30, 2008 ($8.40 per Mcf), we could expect a corresponding fluctuation in the value of the contracts of approximately $0.3 million.

We have also 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, 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 customers price cap arrangements, and may differ from actual results, are as follows:

	Hypothetical adverse change in price		Change in annual pre- tax income
			(in millions)
Fixed price contracts	10.0	%	$	(0.3	)
Price cap contracts	10.0	%	$	(0.3	)

This table does not include two 2.1 million LNG gallon per year renewal options beginning April 1, 2009 that one of our customers possesses related to an LNG price cap contract. Had the contract been included, assuming both renewal periods were exercised, the resulting amount for the price cap contracts would be $(0.6) million.

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 Commissions 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.

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PART II.  OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

An investment in our common stock involves a substantial risk of loss. You should carefully consider the risk factors discussed below together with the risk factors in Part I, Item 1A of our annual report on Form 10-K for the year ended December 31, 2007 and all of the other information included in this report before you decide to purchase shares of our common stock. We believe the risks and uncertainties described below are the most significant we face. The occurrence of any of the following risks could harm our business. In that case, the trading price of our common stock could decline. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also impair our operations.

We have a history of losses and may incur additional losses in the future.

For the nine month period ended September 30, 2008, we incurred pre-tax losses of $18.3 million, which includes derivative losses of $0.3 million. In 2006 and 2007, we incurred pre-tax losses of $89.8 million and $7.7 million, respectively, which include derivative losses of $79.0 million and $0.0 million, respectively. In 2004 and 2005, we reported pre-tax net income of $3.8 million and $28.9 million, respectively, but we would have reported pre-tax net losses related our operations if we excluded derivative gains of $10.6 million and $44.1 million, respectively. For the three-month period ended September 30, 2008, we incur a net loss of $10.5 million, which includes a previously disclosed $6.0 million loss on the sale of natural gas futures contracts, and $500,000 in expenses associated with our support for Proposition 10, the California Alternative Fuel Vehicles and Renewable Energy ballot initiative. In order to execute our strategy, we must continue to invest in developing the natural gas vehicle fuel market, and our natural gas sales activities and station operations may not achieve or maintain profitability. If our natural gas sales activities and station operations continue to lose money, our business will suffer and the price of our common stock may drop.

We will need to raise debt or equity capital to have sufficient cash to fund our capital expenditure program and an inability to access the capital markets may impair our ability to grow our business.

We anticipate that, in order to raise additional funds to fund our 2009 capital expenditure program in full and provide resources for potential acquisition activity or other strategic transactions and vehicle financing programs, we will need to pursue additional equity financing options, which may not be available on terms favorable to us or at all. We may also pursue debt financing options including, but not limited to, the sale of convertible promissory notes or commercial bank financing. Recent and severe lack of liquidity in the debt capital markets and volatility and rapidly falling prices in the equity capital markets have severely and adversely affected capital raising opportunities. If we are unable to obtain debt or equity financing in amounts sufficient to fund our 2009 capital expenditure program in full and provide resources for acquisitions or other strategic transactions, we will be forced to suspend or curtail certain of our planned expansion activities, including new station construction, potential acquisitions or other strategic transactions, and vehicle financing programs, which could harm our business, results of operations, and future prospects.

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We invested $18.7 million supporting Proposition 10, which was not approved by California voters in the November election.

We invested a total of approximately $18.7 million, of which approximately $15 million was invested in the fourth quarter of 2008, supporting the California Alternative Fuel Vehicles and Renewable Energy Initiative, or Proposition 10, a California statewide ballot initiative that called for the creation of a state-administered $5.0 billion fund through the sale of bonds to support development of alternative fuels and energy in California. Proposition 10 failed to pass and this may result in investors and securities analysts lowering their projections and expectations for our future financial performance and growth, which may harm our stock price. Our results for the fourth quarter of 2008 will include substantially higher than anticipated expenses as a result of the $15 million we spent in the fourth quarter of 2008 supporting Proposition 10.

Failure to comply with the terms of our Credit Agreement with PlainsCapital Bank could impair our rights in Dallas Clean Energy, LLC and other secured property.

We recently acquired a 70% interest in Dallas Clean Energy, LLC (DCE), a partnership that manages a biomethane production facility at the McCommas Bluff landfill in Dallas, Texas and holds a lease to the associated landfill gas development rights. We borrowed $18.0 million from PlainsCapital Bank to fund the acquisition and obtained a $12 million line of credit from PlainsCapital to finance capital improvements of the gas processing plant and pay certain costs and expenses of the acquisition. We have utilized $4.2 million of the line of credit as of October 28, 2008. To secure our obligations under the Credit Agreement, we granted PlainsCapital Bank a security interest in 45 of our LNG tanker trailers, certain accounts receivable and inventory, our note receivable from, and our membership interests in, DCE. If we default on the Credit Agreement or otherwise fail to comply with any of the negative or affirmative covenants of the Credit Agreement, PlainsCapital Bank may declare all of the obligations and indebtedness under the Credit Agreement (and related documents) due and payable. In such a scenario, we may lose our right, title and interest in the property that secures such obligations and indebtedness.

Our growth depends in part on environmental regulations and programs mandating the use of cleaner burning fuels, and modification or repeal of these regulations may adversely impact our business.

Our business depends in part on environmental regulations and programs in the United States that promote or mandate the use of cleaner burning fuels, including natural gas for vehicles. In particular, the Ports of Los Angeles and Long Beach have adopted the San Pedro Clean Air Action Plan, which calls for the replacement of 5,300 trucks that meet certain clean truck standards. Industry participants with a vested interest in gasoline and diesel, many of which have substantially greater resources than we do, invest significant time and money in an effort to influence environmental regulations in ways that delay or repeal requirements for cleaner vehicle emissions. An economic recession may result in the delay, amendment or waiver of environmental regulations or the San Pedro Clean Air Action Plan due to the perception that they impose increased costs on the transportation industry that cannot be absorbed in a contracting economy. The delay, repeal or modification of federal or state regulations or programs that encourage the use of cleaner vehicles, and in particular the San Pedro Clean Air Action Plan, could have a detrimental effect on the U.S. natural gas vehicle industry, which, in turn, could slow our growth and adversely affect our business.

Our growth depends in part on tax and related government incentives for clean burning fuels. A reduction in these incentives would increase the cost of natural gas fuel and vehicles for our customers and could significantly reduce our revenue.

Our business depends in part on tax credits, rebates and similar federal, state and local government incentives that promote the use of natural gas as a vehicle fuel in the United States. The federal excise tax credit of $0.50 per gasoline gallon equivalent of CNG and liquid gallon of LNG sold for vehicle fuel use, which began on October 1, 2006, is scheduled to expire December 31, 2009. Based on the service relationship we have with our customers, either we or our customers are able to claim the credit. In 2007 and during the first nine months of 2008, we recorded $17.0 million and $15.5 million of revenue, respectively, related to fuel tax credits, representing approximately 14.5% and 15.5%, respectively, of our total revenue during the period. The failure to extend the federal excise tax credit for natural gas, or the repeal of federal or state tax credits for the purchase of natural gas vehicles or natural gas fueling equipment, could have a detrimental effect on the natural gas vehicle industry, which, in turn, could adversely affect our business and results of operations. In addition, if grant funds were no longer available under existing government programs, the purchase of or conversion to natural gas vehicles and station construction could slow and our business and results of operations could be adversely affected. Any reduction in tax revenues associated with an economic recession or slow-down could result in a significant reduction in funds available for government grants that support vehicle conversion and station construction and impair our ability to grow our business.

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The volatility of natural gas prices could adversely impact the adoption of CNG and LNG vehicle fuel and our business.

In the recent past, the price of natural gas has been volatile, and this volatility may continue. From the end of 1999 through October 28, 2008, the price for natural gas, based on the New York Mercantile Exchange (NYMEX) daily futures data, ranged from a low of $1.65 per Mcf to a high of $19.38 per Mcf. As of October 28, 2008, the NYMEX index price for natural gas was $7.48 per Mcf. Increased natural gas prices affect the cost to us of natural gas and will adversely impact our operating margins in cases where we have committed to sell natural gas at a fixed price without a futures contract or with an ineffective futures contract that does not fully mitigate the price risk or where we otherwise cannot pass on the increased costs to our customers. In addition, higher natural gas prices may cause CNG and LNG to cost more than gasoline and diesel generally, which would adversely impact the adoption of CNG and LNG as a vehicle fuel. Among the factors that can cause price fluctuations in natural gas prices are changes in domestic and foreign supplies of natural gas, domestic storage levels, crude oil prices, the price difference between crude oil and natural gas, price and availability of alternative fuels, weather conditions, level of consumer demand, economic conditions, price of foreign natural gas imports, and domestic and foreign governmental regulations and political conditions.

The use of natural gas as a vehicle fuel may not become sufficiently accepted for us to expand our business.

To expand our business, we must develop new fleet customers and obtain and fulfill CNG and LNG fueling contracts from these customers. We cannot guarantee that we will be able to develop these customers or obtain these fueling contracts. Whether we will be able to expand our customer base will depend on a number of factors, including: the level of acceptance and availability of natural gas vehicles, the growth in our target markets of fueling station infrastructure that supports CNG and LNG sales, and our ability to supply CNG and LNG at competitive prices. Recently, disruption in the capital markets has severely reduced the availability of debt financing. If our potential customers are unable to access credit to purchase natural gas vehicles it may make it difficult or impossible for them to invest in natural gas vehicle fleets, which would impair our ability to grow our business.

A decline in the demand for vehicular natural gas would reduce our revenue and negatively affect our ability to sustain our revenue growth.

We derive our revenue primarily from sales of CNG and LNG as a fuel for fleet vehicles, and we expect this trend will continue. A downturn in demand for CNG and LNG would adversely affect our revenue and ability to sustain and grow our operations. Circumstances that could cause a drop in demand for CNG and LNG vehicle fuel are described in other risk factors and include a reduction in supply of natural gas, changes in governmental incentives, the development of other alternative fuels and technologies, an economic slowdown, prolonged disruption in the capital markets and a sustained increase in the price of natural gas relative to gasoline and diesel.

If the prices of CNG and LNG do not remain sufficiently below the prices of gasoline and diesel, potential fleet customers will have less incentive to purchase natural gas vehicles or convert their fleets to natural gas, which would decrease demand for CNG and LNG and limit our growth.

Natural gas vehicles cost more than comparable gasoline or diesel powered vehicles because converting a vehicle to use natural gas adds to its base cost. If the prices of CNG and LNG do not remain sufficiently below the prices of gasoline or diesel, fleet operators may be unable to recover the additional costs of acquiring or converting to natural gas vehicles in a timely manner, and they may choose not to use natural gas vehicles. Recent and extreme volatility in oil and gas prices demonstrate that it is difficult to predict future transportation fuel costs. This uncertainty, combined with higher costs for natural gas vehicles, may cause potential customers to delay or reject converting their fleets to run on natural gas. In that event, our growth would be slowed and our business would suffer.

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Automobile and engine manufacturers produce very few originally manufactured natural gas vehicles and engines for the U.S. and Canadian markets, which may restrict our sales.

Limited availability of natural gas vehicles restricts their wide scale introduction and narrows our potential customer base. Currently, original equipment manufacturers produce a small number of natural gas engines and vehicles, and they may not make adequate investments to expand their natural gas engine and vehicle product lines. For the North American market, there is only one automobile manufacturer that makes natural gas powered passenger vehicles, and manufacturers of medium and heavy-duty vehicles produce only a narrow range and number of natural gas vehicles. Recent and significant economic challenges confronted by North American car manufacturers may make it difficult or impossible for them to introduce new natural gas vehicles in the North American market. Due to the limited supply of natural gas vehicles, our ability to promote natural gas vehicles and our sales may be restricted, even if there is demand.

Our ability to supply LNG to new and existing customers is restricted by limited production of LNG and by our ability to source LNG without interruption and near our target markets.

Production of LNG in the United States is fragmented. LNG is produced at a variety of smaller natural gas plants around the United States as well as at larger plants where it is a byproduct of their primary natural gas production. It may become difficult for us to obtain additional LNG without interruption and near our current or target markets at competitive prices. If our current LNG liquefaction plant, or any of those from which we purchase LNG, is damaged by severe weather, earthquake or other natural disaster, or otherwise experiences prolonged downtime, our LNG supply will be restricted. In addition, the LNG liquefaction plant we are in the process of building in California may be significantly delayed or never successfully commence full scale commercial operations. If we are unable to supply enough of our own LNG or purchase it from third parties to meet existing customer demand, we may be liable to our customers for penalties. An LNG supply interruption would also limit our ability to expand LNG sales to new customers, which would hinder our growth. Furthermore, because transportation of LNG is relatively expensive, if we are required to supply LNG to our customers from distant locations, our operating margins will decrease on those sales.

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

Some of our LNG supply agreements have take or pay commitments and the new California LNG liquefaction plant has land lease and other fixed operating costs regardless of production and sales levels. Should the market demand for LNG decline or if demand under any existing or any future LNG supply contracts does not continue or grow, overall operating and supply costs may increase and negatively impact our margins.

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

Two third-party LNG suppliers, Williams Gas Processing Company and ExxonMobil Corporation, supplied approximately 47% of the LNG we sold for the year ended December 31, 2007 and supplied 49% of the LNG we sold during the first nine months of 2008. Our contracts with these LNG suppliers generally may be terminated by the supplier on short notice. In addition, under certain circumstances, Williams Gas Processing Company may significantly increase the price of LNG we purchase upon 24 hours notice if Williams costs to produce LNG increases, and we may be required to reimburse Williams for certain other expenses. Our contract with ExxonMobil Corporation, which supplied 15% of the LNG we sold for the year ended December 31, 2007 and 20% during the first nine months of 2008, expires on March 31, 2009. Furthermore, there are a limited number of LNG suppliers in or near the areas where our LNG customers are located. It may be difficult to replace an LNG supplier, and we may be unable to obtain alternate suppliers at acceptable prices, in a timely manner or at all. If significant supply interruptions occur, our ability to meet customer demand will be impaired, customers may cancel orders and we may be subject to supply interruption penalties. If we are subject to LNG price increases, our operating margins may be impaired and we may be forced to sell LNG at a loss under our LNG supply contracts.

If we are unable to obtain natural gas in the amounts needed on a timely basis or at reasonable prices, we could experience an interruption of CNG or LNG deliveries or increases in CNG or LNG costs, either of which could have an adverse effect on our business.

Some regions of the United States and Canada depend heavily on natural gas supplies coming from particular fields or pipelines. Interruptions in field production or in pipeline capacity could reduce the availability of natural gas or possibly create a supply imbalance that increases fuel price. We have in the past experienced LNG supply disruptions due to severe weather in the Gulf of Mexico and plant outages. If there are interruptions in field production, pipeline capacity, equipment failure, liquefaction production or delivery, we may experience supply stoppages which could result in our inability to fulfill delivery commitments. This could result in our being liable for contractual damages and daily penalties or otherwise adversely affect our business.

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

We are in the process of constructing an LNG liquefaction plant in California, which we plan to operate upon completion. The construction, implementation and operation of any plant of this nature has inherent risks. Permitting, environmental issues, lack of materials and lack of human resources, among other factors, could delay implementation and start up of the new LNG liquefaction plant and affect the operation of the plant. Building the new facility could also present increased financial exposure through project delays, cost-overruns and incomplete production capability. As of the date of this report, we anticipate the completion of the LNG liquefaction plant will cost in the aggregate approximately $75 million, which is approximately $20 to $25 million more than we originally anticipated due to design changes and cost increases. If the new plant has higher than expected operating costs and is not able to produce expected amounts of LNG, we may be forced to sell LNG at a price below production costs and we may lose money. Additionally, if the quality of LNG produced at the plant does not meet contractual specifications, our customers may not be required to purchase it, which would harm our business.

If we do not have effective futures contracts in place, increases in natural gas prices may cause us to lose money.

From 2005 to September 30, 2008, we sold and delivered 31% of our total gasoline gallon equivalents of CNG and LNG under contracts that provided a fixed price or a price cap to our customers over terms typically ranging from one to three years, and in some cases up to five years. At any given time, however, the market price of natural gas may rise and our

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obligations to sell fuel under fixed price contracts may be at prices lower than our fuel purchase or production price if we do not have effective futures contracts in place. This circumstance has in the past and may again in the future compel us to sell fuel at a loss, which would adversely affect our results of operations and financial condition. Commencing with the adoption of our revised natural gas hedging policy in February 2007, we expect to purchase futures contracts to hedge our exposure to variability related to substantial fixed price contracts. However, such contracts may not be available or we may not have sufficient financial resources to secure such contacts. In addition, under our hedging policy, we may reduce or remove futures contracts we have in place related to these contracts if such disposition is approved in advance by our board of directors and derivative committee. If we are not economically hedged with respect to our fixed price contracts, we will lose money in connection with those contracts during periods in which natural gas prices increase above the prices of natural gas included in our customers contracts. As of September 30, 2008, we were economically hedged with respect to one of our fixed price contracts that began July 1, 2008. Based on natural gas prices as of September 30, 2008, we incur between $0.4 million and $0.5 million of costs to cover the increased price of natural gas above the inherent price of natural gas embedded in our customers fixed price and price cap contracts where we are not economically hedged over the duration of the contracts. We expect the majority of these costs will be incurred from October 1, 2008 through December 31, 2009.

Our futures contracts may not be as effective as we intend.

Our purchase of futures contracts can result in substantial losses under various circumstances, including if we do not accurately estimate the volume requirements under our fixed price or price cap customer contracts when determining the volumes included in the futures contracts we purchase, or we are required to purchase a futures contract in connection with a bid proposal and ultimately we are not awarded the entire contract or our customer does not fully perform its obligations under the awarded contract. We also could incur significant losses if a counterparty does not perform its obligations under the applicable futures arrangement, the futures arrangement is economically imperfect or ineffective, or our futures policies and procedures are not properly followed or do not work as planned. Furthermore, we cannot assure that the steps we take to monitor our futures activities will detect and prevent violations of our risk management policies and procedures.

A decline in the value of our futures contracts may result in margin calls that would adversely impact our liquidity.

We are required to maintain a margin account to cover losses related to our natural gas futures contracts. Futures contracts are valued daily, and if our contracts are in loss positions at the end of a trading day, our broker will transfer the amount of the losses from our margin account to a clearinghouse. If at any time the funds in our margin account drop below a specified maintenance level, our broker will issue a margin call that requires us to restore the balance. Payments we make to satisfy margin calls will reduce our cash reserves, adversely impact our liquidity and may also adversely impact our ability to expand our business. Moreover, if we are unable to satisfy the margin calls related to our futures contracts, our broker may sell these contracts to restore the margin requirement at a substantial loss to us. At October 28, 2008, we had $0.8 million on deposit related to our futures contracts.

If our futures contracts do not qualify for hedge accounting, our net income and stockholders equity will fluctuate more significantly from quarter to quarter based on fluctuations in the market value of our futures contracts.

We account for our futures activities under Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (SFAS 133), which requires us to value our futures contracts at fair market value in our financial statements. Our futures contracts historically have not qualified for hedge accounting, and therefore we have recorded any changes in the fair market value of these contracts directly in our consolidated statements of operations in the line item derivative (gains) losses along with any realized gains or losses during the period. In the future, we will attempt to qualify all of our futures contracts for hedge accounting under SFAS 133, but there can be no assurances that we will be successful in doing so. To the extent that all or some of our futures contracts do not qualify for hedge accounting, we could incur significant increases and decreases in our net income and stockholders equity in the future based on fluctuations in the market value of our futures contracts from quarter to quarter. For example, we experienced a derivative gain of $33.1 million and $5.7 million for the three months ended September 30, 2005 and June 30, 2008, respectively, and experienced derivative losses of $19.9 million, $0.3 million, $65 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. In July 2008, we sold certain contracts related to the derivative instruments we purchased in April 2008 and we realized a loss of $6.0 million, which was reflected in the financial statements for the quarter ended September 30, 2008. Any negative fluctuations may cause our stock price to decline due to our failure to meet or exceed the expectations of securities analysts or investors.

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

Natural gas operations entail inherent risks, including equipment defects, malfunctions and failures and natural disasters, which could result in uncontrollable flows of natural gas, fires, explosions and other damages. For example, operation of LNG pumps requires special training and protective equipment because of the extreme low temperatures of LNG. LNG tanker trailers have also in the past been, and may in the future be, involved in accidents that result in explosions, fires and other damage. Improper refueling of LNG vehicles can result in venting of methane gas. Additionally, CNG fuel tanks, if damaged or improperly maintained, may rupture and the contents of the tank may rapidly decompress and result in injury. These risks may expose us to liability for personal injury, wrongful death, property damage, pollution and other environmental damage. We may incur substantial liability and cost if damages are not covered by insurance or are in excess of policy limits.

Our business is heavily concentrated in the western United States, particularly in California and Arizona. Economic downturns in these regions could adversely impact our business.

Our operations to date have been concentrated in California and Arizona. For the year ended December 31, 2007 and the nine months ended September 30, 2008, sales in California accounted for 40% and 45%, respectively, and sales in Arizona accounted for 20% and 16%, respectively, of the total amount of gallons we delivered. A continuing decline in the economy in these areas could slow the rate of adoption of natural gas vehicles or impact the availability of incentive funds, both of which could negatively impact our growth.

We provide financing to fleet customers for natural gas vehicles, which exposes our business to credit risks.

We loan to our customers up to 100% of the purchase price of natural gas vehicles. We may also lease vehicles to customers in the future. There are risks associated with providing financing or leasing that could cause us to lose money. Some of these risks include: most of the equipment financed is vehicles, which are mobile and easily damaged, lost or stolen; there is a risk the borrower may default on payments; we may not be able to bill properly or track payments in adequate fashion to sustain growth of this service; and the amount of capital available to us is limited and may not allow us to make loans required by customers. The continued disruption in the credit markets may further reduce the amount of capital available to us and an economic recession or slow down may increase the rate of default by borrowers, leading to an increase in losses on our loan portfolio. As of September 30, 2008 we had $4.4 million outstanding in loans provided to customers to finance natural gas vehicle purchases.

We may incur losses and use working capital if we are unable to place with customers the natural gas vehicles that we or our business partners order from manufacturers.

To ensure availability for our customers, from time to time we enter into binding purchase agreements for natural gas vehicles when there is a production lead time. Although we attempt to arrange for customers to purchase the vehicles before delivery to us, we may be unable to locate purchasers on a timely basis and consequently may need to take delivery of and title to the vehicles. These purchases would adversely affect our cash reserves until such time as we can sell the vehicles to our customers, and we may be forced to sell the vehicles at a loss. At September 30, 2008, we had $10.2 million of deposits on vehicles under binding purchase agreements without corresponding customer orders.

We may also agree to guaranty the purchase of natural gas vehicles on behalf of our business partners. For example, in July 2006, we entered into an agreement with Inland Kenworth, Inc. (Inland) pursuant to which we agreed to deposit certain amounts with Inland, as security for a guaranty, to help fund the acquisition by Kenworth Truck Company (Kenworth) of up to 125 diesel tractors. At September 30, 2008, we had outstanding $5.5 million of deposits under this agreement. If any tractor purchased by Inland remains unsold after a period of 365 days, we must either purchase the tractor or instruct Inland to sell the tractor.

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We have advanced deposits to a business partner to help fund the conversion of diesel tractors to run on LNG. To the extent any converted tractor is not sold within 24 months of the date of the applicable deposit agreement, we may forfeit the deposit related to such vehicle.

We entered into two deposit agreements with Westport in 2007 to facilitate the production of LNG fuel systems for installation in the tractors purchased by Inland. At September 30, 2008, we had outstanding a total of $4.7 million to Westport under these agreements. Repayment of these deposits will occur incrementally upon the sale of the converted tractors to customers; however, to the extent an LNG fuel system incorporated into a tractor is not sold within 24 months of the effective date of the applicable deposit agreement (or such other time period as is agreed by both us and Westport), Westport is not obligated to repay any of the deposit with respect to such LNG fuel system.

There are many risks associated with conducting operations in international markets.

We are in the process of expanding our operations outside of the United States and Canada. For example, in August 2007, we executed a joint venture agreement with Energy Gas del Peru pursuant to which we built and operate a natural gas fueling station in Lima, Peru. Changes in local economic or political conditions in foreign countries could have a material adverse effect on our business, consolidated financial condition, results of operations and cash flows. Additional risks inherent in our international business activities include the following: difficulties in managing international operations, including our ability to timely and cost effectively execute projects; unexpected changes in regulatory requirements; tariffs and other trade barriers that may restrict our ability to enter into new markets; governmental actions that result in the deprivation of contract rights; changes in political and economic conditions in the countries in which we operate, including civil uprisings, riots, kidnappings and terrorist acts; changes in foreign currency exchange rates; potentially adverse tax consequences; restrictions on repatriation of earnings or expropriation of property without fair compensation; difficulties in establishing new international offices and risks inherent in establishing new relationships in foreign countries; and the burden of complying with the various laws and regulations in the countries in which we operate.

Our future plans may involve expanding our business in international markets where we currently do not conduct business. The risks inherent in establishing new business ventures, especially in international markets where local customs, laws and business procedures present special challenges, may affect our ability to be successful in these ventures or avoid losses which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our business is subject to a variety of governmental regulations that may restrict our business and may result in costs and penalties.

We are subject to a variety of federal, state and local laws and regulations relating to the environment, health and safety, labor and employment and taxation, among others. These laws and regulations are complex, change frequently and have tended to become more stringent over time. Failure to comply with these laws and regulations may result in a variety of administrative, civil and criminal enforcement measures, including assessment of monetary penalties and the imposition of remedial requirements. From time to time, as part of the regular overall evaluation of our operations, including newly acquired operations, we may be subject to compliance audits by regulatory authorities.

In connection with our LNG liquefaction activities or the landfill gas processing facility operated by our subsidiary, Dallas Clean Energy, LLC, we need to apply for additional facility permits or licenses to address storm water or wastewater discharges, waste handling, and air emissions related to production activities or equipment operations. This may subject us to permitting conditions that may be onerous or costly. Compliance with laws and regulations and enforcement policies by regulatory agencies could require us to make material expenditures.

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which may distract our officers, directors and employees from the operation of our business. These efforts may not ultimately be effective to maintain adequate internal controls. If we fail to establish and maintain effective controls and procedures for financial reporting, we could be unable to provide timely and accurate financial information. In addition, investor perceptions that our internal controls are inadequate or that we are unable to produce accurate financial statements may negatively affect our stock price.

Our quarterly results of operations have not been predictable in the past and have fluctuated significantly and may not be predictable and may fluctuate in the future.

Our quarterly results of operations have historically experienced significant fluctuations. Our net losses were $58.8 million, $14.6 million, $0.9 million, $3.6 million, $1.5 million, $2.9 million, $5.4 million and $2.4 million for the three months ended September 30, 2006, December 31, 2006, March 31, 2007, June 30, 2007, September 30, 2007, December 31, 2007, March 31, 2008 and June 30, 2008, respectively. For the three-month period ended September 30, 2008, we incurred a net loss of $18.5 million. Our quarterly results may fluctuate significantly as a result of a variety of factors, many of which are beyond our control. If our quarterly results of operations fall below the expectations of securities analysts or investors, the price of our common stock could decline substantially. Fluctuations in our quarterly results of operations historically have primarily been attributable to our derivative gains and losses, but also may be due to a number of other factors, including, but not limited to: our ability to increase sales to existing customers and attract new customers; the addition or loss of large customers; construction cost overruns; the amount and timing of operating costs and capital expenditures related to the maintenance and expansion of our business, operations and infrastructure; changes in the price of natural gas; changes in the prices of CNG and LNG relative to gasoline and diesel; changes in our pricing policies or those of our competitors; the costs related to the acquisition of assets or businesses; regulatory changes; and geopolitical events such as war, threat of war or terrorist actions. Investors in our stock should not rely on the results of one quarter as an indication of future performance as our quarterly revenues and results of operations may vary significantly in the future. Therefore, period-to-period comparisons of our operating results may not be meaningful.

The price of our common stock may be volatile as a result of market conditions unrelated to our company, and the value of your investment could decline.

The trading price of our common stock may fluctuate substantially due to factors in the market beyond our control. These fluctuations could cause you to lose all or part of your investment in our common stock. Factors that could cause fluctuations in the trading price of our common stock include: price and volume fluctuations in the overall stock market from time to time; actual or anticipated changes or fluctuations in our results of operations; actual or anticipated changes in the expectations of investors or securities analysts; actual or anticipated developments in our competitors businesses or the competitive landscape generally; litigation involving us or our industry; domestic and international regulatory developments; general economic conditions and trends; widespread adoption of other alternative fuels and technologies; major catastrophic events or sales of large blocks of our stock. Since our initial public offering, which was completed in May 2007, the price of our common stock has ranged from an intra-day low of $8.06 to an intra-day high of $20.65 through October 28, 2008.

Sales of outstanding shares of our stock into the market in the future could cause the market price of our stock to drop significantly, even if our business is doing well.

If our existing stockholders sell, or indicate an intention to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline. At September 30, 2008, 44,641,520 shares of our common stock were outstanding. The 11,500,000 shares sold in our initial public offering in addition to the 4,419,192 shares of common stock and the shares of common stock subject to warrants sold in our offering closed November 3, 2008 are freely tradable without restriction or further registration under federal securities laws unless purchased by our affiliates. Shares held by non-affiliates for more than six months may generally be sold without restriction, other than a current public information requirement, and may be sold freely without any restrictions after one year. All other outstanding shares of common stock may be sold under Rule 144 under the Securities Act, subject to applicable restrictions.

In addition, as of September 30, 2008, there were 7,018,955 shares underlying outstanding options and 15,000,000 shares underlying an outstanding warrant. In our offering of common stock and warrants that closed November 3, 2008, we issued Series I Warrants to purchase up to an aggregate of 3,314,394 shares of common stock, and Series II Warrants to purchase up to an aggregate of 1,136,364 shares of common stock. On November 12, 2008, all of the Series II Warrants had been excercised on a cashless basis resulting in the issuance of 1,134,759 shares of our common stock to the Series II Warrant holders. All shares subject to outstanding options and warrants are eligible for sale in the public market to the extent permitted by the provisions of various option and warrant agreements and Rule 144. If these additional shares are sold, or if it is perceived that they will be sold in the public market, the trading price of our stock could decline.

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A majority of our stock is beneficially owned by a single stockholder whose interests may differ from yours and who will be able to exert significant influence over our corporate decisions, including a change of control.

As of September 30, 2008, Boone Pickens and affiliates (including Madeleine Pickens, his wife) beneficially owned in the aggregate 58.9% of our outstanding common stock, inclusive of the 15,000,000 shares underlying the warrant held by Mr. Pickens. As a result, Mr. Pickens will be able to influence or control matters requiring approval by our stockholders, including the election of directors and the approval of mergers, acquisitions or other extraordinary transactions. Mr. Pickens may also have interests that differ from yours and may vote in a way with which you disagree and which may be adverse to your interests. This concentration of ownership may have the effect of delaying, preventing or deterring a change of control of our company, could deprive our stockholders of an opportunity to receive a premium for their stock as part of a sale of our company, and might ultimately affect the market price of our stock. Conversely, this concentration may facilitate a change in control at a time when you and other investors may prefer not to sell.

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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, 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 September 30, 2008, we have used the net proceeds from the offering as follows:

· construction of our LNG liquefaction plant in California ($56.7 million),

· construction and installation of CNG and LNG stations ($18.2 million),

· financing customer vehicle purchases ($4.1 million), and

· working capital ($14.3 million).

The balance of the proceeds has been from time to time 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

None.

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Item 5. Other Information

Sixth Amendment to Lease Agreement

On August 1, 2008, we and Clean Energy, our wholly-owned subsidiary, entered into a Sixth Amendment to Lease Agreement with Bixbybit-Bixby Office Park, LLC, the landlord, related to our executive offices located in Seal Beach, CA. Pursuant to the amendment:

· We relocated from certain premises, comprising approximately 16,881 square feet of rentable space, on the second floor of 3020 Old Ranch Parkway, Seal Beach, CA 90740, to new premises, comprising approximately 19,881 rentable square feet of space, on the fourth floor of such building.

· Additional premises subleased by us at our executive offices, which comprise an aggregate of 11,196 square feet of rentable space, were made subject to the terms of the lease agreement.

· The term of the lease agreement was extended to January 31, 2015.

· The aggregate monthly base rent for the full premises at our executive offices, commencing on November 1, 2008, will be $66,344 per month for the first 12 months, and will increase for each subsequent 12 month period by specified amounts, up to a maximum aggregate monthly base rent of $84,334 at the end of the lease term.

· We paid the landlord $23,297 upon the signing of the amendment and an additional $27,400 on November 1, 2008, the first day of the new lease term. Additionally, we made an additional security deposit with the landlord of $48,690 upon the signing of the amendment.

A complete copy of the amendment is attached as Exhibit 10.3 to this report and is incorporated herein by reference. The summary of the transaction set forth above does not purport to be complete and is qualified in its entirety by reference to the amendment.

This disclosure is provided in lieu of disclosure under Item 1.01 of Form 8-K.

First Amendment to Base Contract for Sale and Purchase of Natural Gas and Guaranty

On November 7, 2008, Clean Energy, our wholly-owned subsidiary, entered into a First Amendment to Base Contract for Sale and Purchase of Natural Gas with Shell Energy North America (US), L.P., or Shell. Pursuant to the amendment, Clean Energy may purchase natural gas on credit from Shell up to the lower of (i) $15.0 million, or (ii) the amount of any dollar limit contained in a guaranty provided by us pursuant to the amendment, except that Clean Energy may not purchase any natural gas on credit if a material adverse change or event of default, in each case as defined in the amendment, has occurred and is continuing.

In connection with the amendment, on November 7, 2008, we executed a guaranty in favor of Shell pursuant to which we agreed to guarantee the timely payment when due of Clean Energys obligations to Shell under the base contract, as amended. Our liability under the guaranty will not exceed $15.0 million, plus reasonable attorneys fees and expenses.

Complete copies of the First Amendment to Base Contract for Sale and Purchase of Natural Gas and the Guaranty are attached as Exhibits 10.4 and 10.5 to this report, respectively, and are incorporated herein by reference. The summary of the agreements described above does not purport to be complete and is qualified in its entirety by reference to such agreements.

This disclosure is provided in lieu of disclosure under Items 1.01 and 2.03 of Form 8-K.

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Item 6. Exhibits

(a)	Exhibits

10.1	LNG Sales Agreement dated July 1, 2008 between Williams Four Corners LLC and the registrant. +

10.2	Share Purchase Agreement dated September 5, 2008, among the registrant, American Honda Motor Co., Inc., John G. Armstrong (sole trustee of The FuelMaker Trust), and FuelMaker Corporation.

10.3	Sixth Amendment to Lease Agreement dated August 1, 2008 among the registrant, Clean Energy and Bixbybit-Bixby Office Park, LLC.

10.4	First Amendment to Base Contract for Sale and Purchase of Natural Gas dated November 7, 2008, between Clean Energy and Shell Energy North America (US), L.P.

10.5	Guaranty dated November 7, 2008, executed by the registrant in favor of Shell Energy North America (US), L.P.

31.1	Certification of Andrew J. Littlefair, President and Chief Executive Officer, pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities and Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certification of Richard R. Wheeler, Chief Financial Officer, pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities and Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, executed by Andrew J. Littlefair, President and Chief Executive Officer, and Richard R. Wheeler, Chief Financial Officer.

+	Portions of this exhibit have been omitted pursuant to a request for confidential treatment and the non-public information has been filed separately with the SEC.

SIGNATURE

Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	CLEAN ENERGY FUELS CORP.

Date: November 14, 2008	By:	/s/	Richard R. Wheeler
			Richard R. Wheeler
			Chief Financial Officer (Principal financial officer and duly authorized to sign on behalf of the registrant)

Form: 10-Q

Documents

Item 4T. Controls and Procedures

10-Q: Quarterly report pursuant to Section 13 or 15(d)

Item 4T.  Controls and Procedures

Item 4T. Controls and Procedures