Edgar Filing: Clean Energy Fuels Corp.

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2007

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

(Registrant’s telephone number, including area code)

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

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

Large accelerated filer o

Accelerated filer o

Non-accelerated filer x

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

As of August 1, 2007, there were 44,193,411 shares of the registrant’s common stock, par value $0.0001 per share, issued and outstanding.

CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES
INDEX

Table of Contents

PART I. – FINANCIAL INFORMATION

	Item 1. – Financial Statements (unaudited)

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

	Item 3. – Quantitative and Qualitative Disclosures About Market Risk

	Item 4. – Controls and Procedures

PART II. - OTHER INFORMATION

	Item 1. – Legal Proceedings

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

	Item 3. – Defaults upon Senior Securities

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

	Item 5. – Other Information

	Item 6. – Exhibits

PART I. – FINANCIAL INFORMATION

Item 1. – Financial Statements (Unaudited)

Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Balance Sheets

December 31, 2006 and June 30, 2007 (unaudited)

	December 31, 2006			June 30, 2007

Assets
Current assets:
Cash and cash equivalents	$	937,445		$	110,972,077
Accounts receivable, net of allowance for doubtful accounts of $352,050 and $429,821 as of December 31, 2006 and June 30, 2007, respectively	10,997,328			11,125,055
Other receivables	37,818,905			16,714,049
Inventories, net	2,558,689			2,429,941
Prepaid expenses and other current assets	4,862,335			5,980,461
Total current assets	57,174,702			147,221,583

Land, property and equipment, net	54,888,739			70,272,762
Capital lease receivables	1,412,500			963,000
Notes receivable and other long term assets	2,499,106			10,229,432
Goodwill and other intangible assets	20,957,589			20,939,844
Total assets	$	136,932,636		$	249,626,621

Liabilities and Stockholders’ Equity
Current liabilities:
Current portion of long term debt and capital lease obligations	$	57,499		$	60,435
Accounts payable	6,697,363			9,961,115
Accrued liabilities	5,023,051			6,039,609
Deferred revenue	585,505			590,520
Total current liabilities	12,363,418			16,651,679

Long term debt and capital lease obligations, less current portion	224,897			193,928
Other long term liabilities	1,428,464			1,432,665
Total liabilities	14,016,779			18,278,272

Commitments and contingencies

Stockholders’ equity:
Preferred stock, par value $0.0001 per share. Authorized 1,000,000 shares; issued and outstanding, no shares	—			—
Common stock, par value $0.0001 per share. 99,000,000 shares authorized; issued and outstanding 34,192,161 shares and 44,193,411 shares at December 31, 2006 and June 30, 2007, respectively	3,419			4,419
Additional paid-in capital	181,678,861			294,129,852
Retained earnings (accumulated deficit)	(60,192,221		)	(64,625,302		)
Accumulated other comprehensive income	1,425,798			1,839,380
Total stockholders’ equity	122,915,857			231,348,349
Total liabilities and stockholders’ equity	$	136,932,636		$	249,626,621

See accompanying notes to condensed consolidated financial statements.

Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Statements of Operations

For the Three-Month and Six-Month Periods Ended

June 30, 2006 and 2007

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2007			2006			2007

Revenue	$	21,521,127		$	30,663,597		$	42,554,992		$	58,830,640
Operating expenses:
Cost of sales	17,552,518			22,526,562			36,695,244			43,847,722
Derivative (gains) losses	—			—			282,348			—
Selling, general and administrative	4,383,543			10,440,718			9,265,684			16,740,596
Depreciation and amortization	1,401,009			1,700,164			2,600,729			3,276,220
Total operating expenses	23,337,070			34,667,444			48,844,005			63,864,538
Operating income (loss)	(1,815,943		)	(4,003,847		)	(6,289,013		)	(5,033,898		)

Interest (income), net	(245,494		)	(546,750		)	(410,800		)	(838,963		)
Other (income) expense, net	(67,038		)	55,805			(42,066		)	179,177
Income (loss) before income taxes	(1,503,411		)	(3,512,902		)	(5,836,147		)	(4,374,112		)
Income tax expense (benefit)	(446,513		)	50,000			(1,733,336		)	58,969
Net income (loss)	$	(1,056,898	)	$	(3,562,902	)	$	(4,102,811	)	$	(4,433,081	)

Earnings (loss) per share
Basic	$	(0.03	)	$	(0.09	)	$	(0.14	)	$	(0.12	)
Diluted	(0.03		)	(0.09		)	(0.14		)	(0.12		)

Weighted average common shares outstanding
Basic	32,010,322			38,149,455			29,098,274			36,071,554
Diluted	32,010,322			38,149,455			29,098,274			36,071,554

See accompanying notes to condensed consolidated financial statements.

Clean Energy Fuels Corp.

Condensed Consolidated Statement of Cash Flows

For the Six-Month Periods Ended June 30, 2006 and 2007

(Unaudited)

	Six months ended June 30,
	2006			2007
Cash flows from operating activities:
Net loss	$	(4,102,811	)	$	(4,433,081	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization	2,600,729			3,276,220
Provision for doubtful accounts	103,152			892,910
Unrealized (gain) loss on futures contracts	8,956,599			—
Loss on disposal of assets	—			179,177
Deferred income taxes	(1,733,336		)	—
Stock option expense	7,360			3,832,654
Changes in operating assets and liabilities:
Accounts and other receivables	(3,464,198		)	12,412,862
Inventories	246,904			128,748
Capital lease receivables	449,500			449,500
Margin deposits on futures contracts	196,600			—
Prepaid expenses and other assets	(882,432		)	(3,314,238		)
Accounts payable	(4,203,411		)	2,054,456
Income taxes payable	(6,300,000		)	(58,969		)
Accrued expenses and other	(517,715		)	1,357,588
Net cash provided by (used in) operating activities	(8,643,059		)	16,777,827

Cash flows from investing activities:
Purchases of property and equipment	(6,710,103		)	(17,030,839		)
Net cash used in investing activities	(6,710,103		)	(17,030,839		)

Cash flows from financing activities:
Repayment of notes payable and capital lease obligations	(289,729		)	(28,033		)
Proceeds from issuance of common stock	21,951,788			110,315,677
Net cash provided by financing activities	21,662,059			110,287,644
Net increase in cash	6,308,897			110,034,632
Cash, beginning of period	28,763,445			937,445
Cash, end of period	$	35,072,342		$	110,972,077

Supplemental disclosure of cash flow information
Income taxes paid	6,301,353			200
Interest paid	198,196			50,873

See accompanying notes to condensed consolidated financial statements.

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

Note 1 — General

Nature of Business: Clean Energy Fuels Corp. (the “Company”) is engaged in the business of providing natural gas fueling solutions to its customers in the United States and Canada. The Company has a broad customer base in a variety of markets including public transit, refuse, airports and regional trucking. Clean Energy operates over 170 fueling locations principally in California, Texas, Colorado, Maryland, New York, New Mexico, Washington, Massachusetts, Georgia, and Arizona within the United States, and in British Columbia and Ontario within Canada.

Basis of Presentation: The accompanying interim unaudited condensed consolidated financial statements include the accounts of the Company and its subsidiaries, and, in the opinion of management, reflect all adjustments, which include only normal recurring adjustments, necessary to state fairly the Company’s financial position, results of operations and cash flows for the three and six month periods ended June 30, 2006 and 2007. All intercompany accounts and transactions have been eliminated in consolidation. The three and six month periods ended June 30, 2006 and 2007 are not necessarily indicative of the results to be expected for the year ended December 31, 2007 or for any other interim period or for any future year.

Certain information and disclosures normally included in the notes to consolidated financial statements have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), but the resultant disclosures contained herein are in accordance with accounting principles generally accepted in the United States of America as they apply to interim reporting. The consolidated condensed financial statements should be read in conjunction with the consolidated financial statements as of and for the year ended December 31, 2006 that are included in the Company’s Form S-1 filed with the SEC.

Note 2 — Derivative Financial Instruments

The Company, in an effort to manage its natural gas commodity price risk exposures, utilizes derivative financial instruments. The Company often enters into natural gas futures contracts that are over-the-counter swap transactions that convert its index-based gas supply arrangements to fixed-price arrangements. The Company accounts for its derivative instruments in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. SFAS No. 133 requires the recognition of all derivatives as either assets or liabilities in the consolidated balance sheet and the measurement of those instruments at fair value. The Company’s derivative instruments did not qualify for hedge accounting under SFAS No. 133 for the year ended December 31, 2006. As such, changes in the fair value of the derivatives were recorded directly to the consolidated statements of operations during the year. The Company did not have any futures contracts outstanding during the three or six month periods ended June 30, 2007.

The Company marks to market its open futures position at the end of each period and records the net unrealized gain or loss during the period in derivative (gains) losses in the accompanying condensed consolidated statements of operations. For the six month periods ended June 30, 2006 and 2007, the Company’s unrealized net loss amount totaled $8,956,599 and $0, respectively.

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

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

Note 3 — Fixed Price and Price Cap Sales Contracts

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

As part of determining the fixed price or price cap in the contracts, the Company works with its customers to determine their future usage over the contract term. However, the Company’s customers do not agree to purchase a minimum amount of volume or guarantee their volume of purchases. There is not an explicit volume in the contract as the Company agrees to sell its customers volumes on an “as needed” basis, also known as a “requirements contract.” The volume required under these contracts varies each month, and is not subject to any minimum commitments. For U.S. generally accepted accounting purposes, there is not a “notional amount,” which is one of the required conditions for a transaction to be a derivative pursuant to the guidance in SFAS No. 133.

The Company’s sales agreements that fix the price or cap the price of LNG or CNG that it sells to its customers are, for accounting purposes, firm commitments, and U.S. generally accepted accounting principles do not require or allow the Company to record a loss until the delivery of the gas and corresponding sale of the product occurs. When the Company enters into these fixed price or price cap contracts with its customers, the price is set based on the prevailing index price of natural gas at that time. However, the index price of natural gas constantly changes, and a difference between the fixed price of the natural gas included in the customer’s contract price and the corresponding index price of gas typically develops after the Company enters into the sales contract. The Company has entered into several contracts to sell LNG or CNG to customers at a fixed price or an index-based price that is subject to a fixed price cap. The Company has also generally entered into natural gas futures contracts to offset economically the adverse impact of rising natural gas prices. The Company has also periodically sold the underlying futures contacts related to its fixed price and price cap contracts. At June 30, 2007, the Company did not own any futures contracts related to its fixed price and price cap contracts. Since entering into the fixed price and price cap contracts, in general, the price of natural gas has increased.

From an accounting perspective, during periods of rising natural gas prices, the Company’s futures contracts have generally been marked-to-market through the recognition of a derivative asset and a corresponding derivative gain in its statements of operations. However, because the Company’s contracts to sell LNG or CNG to its customers at fixed prices or an index-based price that is subject to a fixed price cap are not derivatives for purposes of U.S. generally accepted accounting principles, a liability or a corresponding loss has not been recognized in the Company’s statements of operations during this historical period of rising natural gas prices for the future commitments under these contracts. As a result, the Company’s statements of operations do not reflect its firm commitments to deliver LNG or CNG at prices that are below, and in some cases, substantially below, the prevailing market price of natural gas (and therefore LNG or CNG).

The following table summarizes important information regarding the Company’s fixed price and price cap supply contracts under which it is required to sell fuel to its customers as of June 30, 2007:

	Estimated volumes(a)	Average price(b)		Contracts duration
CNG fixed price contracts	2,506,146	$	1.06	through 12/13
LNG fixed price contracts	21,609,891	$	.37	through 7/09
CNG price cap contracts	5,720,949	$	.87	through 12/09
LNG price cap contracts	10,751,067	$	.57	through 12/08

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

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

At June 30, 2007, based on natural gas futures prices as of that date, the Company estimates it will incur between $7.0 million and $8.6 million to cover the increased price of natural gas above the inherent price of natural gas embedded in its customer’s fixed price and price cap contracts over the duration of the contracts. These estimates were based on natural gas futures prices on June 30, 2007, and these estimates may change based on future natural gas prices and may be significantly higher or lower. The Company’s volumes under these contracts, in gasoline gallon equivalents, expire as follows:

July 1, 2007 through December 31, 2007		11,378,184
2008		14,670,803
2009		2,486,896
2010		230,000
2011		230,000
2012		230,000
2013		230,000

Note 4 —Other Receivables

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

	December 31, 2006		June 30, 2007

Loans to customers to finance vehicle purchases	$	816,837	$	1,250,265
Advances to vehicle manufacturers	2,465,776		3,609,664
Fuel credit refunds	3,810,109		3,810,109
Futures contracts deposit receivable	22,900,000		—
Income tax receivable	5,600,071		5,541,352
Other	2,226,112		2,502,659
	$	37,818,905	$	16,714,049

Note 5 — Land, Property and Equipment

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

	December 31, 2006			June 30, 2007
Land	$	472,616		$	472,616
LNG liquefaction plant	12,898,178			12,898,178
Station equipment	36,913,552			40,653,103
LNG trailers	8,253,415			11,157,806
Other equipment	6,144,553			6,483,221
Construction in progress	7,304,612			18,994,049
	71,986,926			90,658,973
Less accumulated depreciation	(17,098,187		)	(20,386,211		)
	$	54,888,739		$	70,272,762

Note 6 — Accrued Liabilities

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

	December 31, 2006		June 30, 2007
Salaries and wages	$	1,286,196	$	1,631,896
Accrued gas purchases	1,566,847		2,064,931
Other	2,170,008		2,342,782
	$	5,023,051	$	6,039,609

Note 7 — 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		Six Months Ended
	June 30, 2006	June 30, 2007	June 30, 2006	June 30, 2007
Basic and diluted:
Weighted average number of common shares outstanding	32,010,322	38,149,455	29,098,274	36,071,554

Certain securities were excluded from the diluted earnings per share calculations at June 30, 2006 and 2007, respectively, as the inclusion of the securities would be anti-dilutive to the calculation. The amounts outstanding as of June 30, 2006 and 2007 for these instruments are as follows:

	June 30,
	2006	2007

Options	2,417,750	5,187,500
Warrants	—	15,000,000

Note 8 — Comprehensive Income

The following table presents the Company’s comprehensive income for the six-month periods ended June 30, 2006 and 2007:

	Six Months Ended June 30,
	2006			2007
Net loss	$	(4,102,811	)	$	(4,433,081	)
Foreign currency translation adjustments	275,272			413,582

Comprehensive loss	$	(3,827,539	)	$	(4,019,499	)

Note 9 — Stock Based Compensation

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2007		2006		2007

Stock options
Share-based compensation expense	$	—	$	3,787,654	$	—	$	3,787,654
Income tax benefit	—		—		—		—
Share-based compensation expense, net of tax	$	—	$	3,787,654	$	—	$	3,787,654

Stock Options

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

	Number of Shares		Weighted- Average Exercise Price

Outstanding at December 31, 2006	2,402,250		$	2.97
Granted	2,786,500		12.00
Exercised	(1,250	)	2.96
Outstanding at June 30, 2007	5,187,500		7.82

Exercisable at June 30, 2007	2,866,667		4.43

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants in 2007:

	Six Months Ended June 30, 2007

Dividend yield	0	%
Expected volatility	55.0	%
Risk-free interest rate	4.94	%
Expected life in years	5.7

The weighted average grant date fair value of options granted using these assumptions was $6.71 per share for the six months ended June 30, 2007.

Note 10 — Use of Estimates

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

Note 11 — Environmental Matters, Litigation, Claims, Committments and Contingencies

The Company is subject to federal, state, local, and foreign environmental laws and regulations. The Company does not anticipate any expenditures to comply with such laws and regulations which would have a material impact on the Company’s consolidated financial position, results of operations, or liquidity. The Company believes that its operations comply, in all material respects, with applicable federal, state, local and foreign environmental laws and regulations.

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

As of June 30, 2007, the Company had entered into purchase commitments totaling $29,208,000 related to constructing an LNG liquefaction plant, of which $7,827,000 had been paid as of this date.

Note 12 — Income Taxes

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

The Company adopted the provisions of FIN No. 48 on January 1, 2007. On December 31, 2006 and June 30, 2007, the Company’s liabilities for uncertain tax positions were not significant.

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

The Company is subject to audit by tax authorities for varying periods in various tax jurisdictions. Taxable years from 2002 and 2003, respectively, are subject to audit for state and U.S. federal corporate income tax purposes. The Company is not currently under audit by a taxing authority. Disputes may arise during the course of such audits as to facts and matters of law.

During June 2007, the Company requested permission from the Internal Revenue Service to change its method of accounting for its derivative gains and losses related to futures contracts that are sold in one period but relate to a subsequent period. On July 5, 2007, the Internal Revenue Service granted the Company’s request. The Company will begin reporting the income tax impact of the change in the third quarter of 2007. The Company anticipates that the adoption of the new method will create a federal and state alternative minimum tax liability in the amount of $807,000 for 2007, which liability will generate a corresponding alternative minimum tax credit in the same amount which can be carried forward indefinitely to offset future regular income tax liability in excess of the tentative minimum tax.

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

The discussion in this section contains forward-looking statements. These statements relate to future events or our future financial performance. We have attempted to identify forward-looking statements by terminology such as “anticipate,” “believe,” “can,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “should,” “would” or “will” or the negative of these terms or other comparable terminology. These statements are only predictions and involve known and unknown risks, uncertainties and other factors, which could cause our actual results to differ from those projected in any forward-looking statements we make. Please read “Risk Factors” in Part II, Item 1A of this report for a discussion of some of these risks and uncertainties. This discussion should be read with our financial statements and related notes included elsewhere in this report.

We provide natural gas solutions for vehicle fleets in the United States and Canada. Our primary business activity is supplying CNG and LNG vehicle fuels to our customers. We also build, operate and maintain fueling stations, and help our customers acquire and finance natural gas vehicles and obtain local, state and federal clean air incentives. Our customers include fleet operators in a variety of markets, such as public transit, refuse hauling, airports, taxis and regional trucking.

Overview

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

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

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

Gasoline gallon equivalents delivered (in millions)	Year ended December 31, 2004	Year ended December 31, 2005	Year ended December 31, 2006	Three months ended June 30, 2006	Six months ended June 30, 2006	Three months ended June 30, 2007	Six months ended June 30, 2007
CNG	30.6	36.1	41.9	10.2	19.7	12.3	23.4
LNG	15.7	20.7	26.5	6.7	12.8	7.0	13.7

Total	46.3	56.8	68.4	16.9	32.5	19.3	37.1

Operating data
Revenue	$	57,641,605	$	77,955,083	$	91,547,316		21,521,127		$	42,554,992		30,663,597		$	58,830,640
Net income (loss)	2,129,241		17,257,587		(77,500,741		)	(1,056,898	)	(4,102,811		)	(3,562,902	)	(4,433,081		)

Key trends in 2004, 2005, 2006 and the first six months of 2007. Vehicle fleet demand for natural gas fuels increased significantly from January 1, 2004 through the first six months of 2007. This growth in demand was attributable primarily to the rising prices of gasoline and diesel relative to CNG and LNG during these periods and increasingly stringent environmental regulations affecting vehicle fleets. We capitalized on this growing demand by securing new fleet customers in a variety of markets, including public transit, refuse hauling, airports, taxis and regional trucking. Sales to previously existing customers also increased during these periods as they expanded their fleets.

The annual amount of CNG and LNG gasoline gallon equivalents we delivered increased by 47.7% from 2004 to 2006. The amount of CNG and LNG gasoline gallon equivalents we delivered from the first six months of 2006 to the first six months of 2007 increased by 14.1%. The increase in gasoline gallon equivalents delivered, together with generally higher prices we charged our customers due to higher natural gas prices, contributed to increased revenues during these periods. Our cost of sales also increased during these periods, which was attributable primarily to increased costs related to delivering more CNG and LNG to our customers and the increased price of natural gas.

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

Sources of liquidity and anticipated capital expenditures. In May 2007, we completed our initial public offering of 10,000,000 shares of common stock at a public offering price of $12.00 per share. Net cash proceeds from the initial public offering were approximately $108.6 million, after deducting underwriting discounts, commissions and offering expenses. Historically, our principal sources of liquidity have been cash provided by operations, capital contributions from our stockholders, our cash and cash equivalents and, during the third and fourth quarters of fiscal 2006, a revolving line of credit with Boone Pickens, a director and our largest stockholder. The line of credit was used to fund margin requirements on certain derivative contracts and was terminated in December 2006. In 2007, we expect to spend our cash primarily on building an LNG liquefaction plant in California, constructing new fueling stations, purchasing new LNG tanker trailers, financing natural gas vehicle purchases by our customers, and for general corporate purposes, including making deposits to suppport our derivative activities, geographic expansion (domestically and internationally), expanding our sales and marketing activities, and for working capital for our expansion. For more information, please read “Liquidity and Capital Resources” below.

Volatility in operating results related to futures contracts. Historically, we have purchased futures contracts from time to time to help mitigate our exposure to natural gas price fluctuations in current periods and in future periods. Gains and losses related to our futures activities, which appear in the line item derivative (gains) losses, have materially impacted our results of operations in recent periods. For the years ended December 31, 2004, 2005 and 2006 derivative (gains) losses were $(10,572,349), $(44,067,744), and $78,994,947, respectively. For the six month periods ended June 30, 2006 and 2007, derivative (gains) losses were $282,348 and $0, respectively. For this reason and others, we caution investors that our past operating results may not be indicative of future results. For more information, 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, please read “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 six months ended June 30, 2007, CNG represented 63% and LNG represented 37% of our natural gas sales (on a gasoline gallon equivalent basis). To a lesser extent, we generate revenues by operating and maintaining natural gas fueling stations that are owned either by us or our customers. Substantially all of our operating and maintenance revenues are generated from CNG stations, as owners of LNG stations tend to operate and maintain their own stations. In addition, we generate a small portion of our revenues by designing and constructing fueling stations and selling or leasing those stations to our customers. Substantially all of our station sale and leasing revenues have been generated from CNG stations. In 2006, we also began providing vehicle finance services to our customers.

CNG Sales

We sell CNG through fueling stations located on our customers’ properties and through our network of public access fueling stations. At these CNG fueling stations, we procure natural gas from local utilities or brokers under standard, floating-rate arrangements and then compress and dispense it into our customers’ vehicles. Our CNG sales are made primarily through contracts with our fleet customers. Under these contracts, pricing is determined primarily on an index-plus basis, which is calculated by adding a margin to the local index or utility price for natural gas. We sell a small amount of CNG under

fixed-price contracts and also provide price caps to certain customers on their index-plus pricing arrangement. We no longer intend to offer price-cap contracts to our customers, but we will continue to perform our obligations under price-cap contracts we entered into before January 1, 2007. Our fleet customers typically are billed monthly based on the volume of CNG sold at a station. A smaller portion of our CNG sales are on a per fill-up basis at prices we set at the pump based on prevailing market conditions. These customers typically pay using a credit card at the station.

LNG Sales

We sell substantially all of our LNG to fleet customers, who typically own and operate their fueling stations. We also sell a small volume of LNG to customers for non-vehicle use. We procure LNG from third-party producers and also produce LNG at our liquefaction plant in Texas. For LNG that we purchase from third-parties, we typically enter into “take or pay” contracts that require us to purchase minimum volumes of LNG at index-based rates. We deliver LNG via our fleet of 58 tanker trailers to fueling stations, where it is stored and dispensed in liquid form into vehicles. We sell LNG principally through supply contracts that are priced on either a fixed-price or index-plus basis. 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. We no longer intend to offer price-cap contracts to our customers, but we will continue to perform our obligations under price-cap contracts we entered into before January 1, 2007. Our LNG contracts provide that we charge our customers periodically based on the volume of LNG supplied.

Government Incentives

From October 1, 2006 through September 30, 2009, we may receive a Volumetric Excise Tax Credit (VETC) of $0.50 per gasoline gallon equivalent of CNG and $0.50 per liquid gallon of LNG that we sell as vehicle fuel. Based on the service relationship we have with our customers, either we or our customers are able to claim the credit. We expect the tax credit will continue to factor into the price we charge our customers for CNG and LNG in the future. The legislation that created this tax credit also increased the federal excise taxes on sales of CNG from $0.061 to $0.183 per gasoline gallon equivalent and on sales of LNG from $0.119 to $0.243 per LNG gallon. These new excise tax rates are approximately the same as those for gasoline and diesel fuel.

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

Operation and Maintenance

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

Station Construction

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

Vehicle Acquisition and Finance

In 2006, we commenced offering vehicle finance services for some of our customers’ purchases of natural gas vehicles or the conversion of their existing gasoline or diesel powered vehicles to operate on natural gas. Through these services, we loan to our customers up to 100% of the purchase price of their natural gas vehicles. We may also lease vehicles in the future. Where appropriate, we apply for and receive state and federal incentives associated with natural gas vehicle purchases and pass these benefits through to our customers. We may also secure vehicles to place with customers prior to receiving a firm order from our customers, which we may be required to purchase if our customer fails to purchase the vehicle as anticipated. For the six month period ended June 30, 2007, we generated $135,000 of revenue from vehicle finance activities.

Volatility of Earnings and Cash Flows

Our earnings and cash flows historically have fluctuated significantly from period to period based on our futures activities, as our futures contracts to date have not qualified for hedge accounting under SFAS No. 133. See “Critical Accounting Policies—Derivative Activities” below. We have therefore recorded any changes in the fair market value of these contracts directly in our statements of operations in the line item derivative (gains) losses along with any realized gains or losses generated during the period. For example, we experienced derivative gains of $33.1 million for the three months ended September 30, 2005 and experienced derivative losses of $19.9 million, $0.3 million, $65.0 million and $13.7 million for the three months ended December 31, 2005, March 31, 2006, September 30, 2006 and December 31, 2006, respectively. We had no derivative gains or losses for the three months ended June 30, 2006, March 31, 2007 and June 30, 2007. Commencing with the adoption of our revised natural gas hedging policy in February 2007, we plan to structure all subsequent futures contracts as cash flow hedges under SFAS No. 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 the contracts from period to period.

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

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

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

Risk Management Practices Before February 2007

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

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

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

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

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

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

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

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

Futures settlement year		Volume covered by futures (gasoline gallon equivalents)
2008		161,300,000
2009		201,625,000
2010		201,625,000
2011		201,625,000

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

Adoption of Revised Natural Gas Hedging Policy in February 2007

In an effort to mitigate the volatility of our earnings related to our futures contracts and to reduce our risk related to fixed-price sales contracts, our board of directors revisited our risk management policies and procedures and adopted a revised natural gas hedging policy which restricts our ability to purchase natural gas futures contracts and offer fixed-price sales contracts to our customers. Unless otherwise agreed in advance by the board of directors and the derivative committee, we will conduct our futures activities and offer of fixed-price sales contracts pursuant to the policy as follows:

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

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

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

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

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

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

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

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

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

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

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

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

8. We will attempt to qualify all futures contracts for hedge accounting as cash flow hedges under SFAS No. 133.

Due to the restrictions of our revised hedging policy, as well as the rising cost of futures contracts resulting from the loss of Mr. Pickens’ guarantee to Sempra, we expect to offer significantly fewer fixed-price sales contracts to our customers. If we do offer a fixed-price sales contract, we anticipate including a price component that would cover our increased costs as well as a return on our estimated cash requirements over the duration of the underlying futures contract. The amount of this price component will vary based on the anticipated volume to be covered under the fixed-price sales contract.

Critical Accounting Policies

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

Revenue Recognition

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

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

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

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

Derivative Activities

We account for our derivative instruments, specifically our futures contracts, in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. SFAS No. 133 requires the recognition of all derivatives as either assets or liabilities in the consolidated balance sheet and the measurement of those instruments at fair value. Our derivatives did not qualify for hedge accounting under SFAS No. 133 for the years ended December 31, 2004, 2005 and 2006. As such, changes in the fair value of the derivatives for the years ended December 31, 2004, 2005 and 2006, were recorded directly to our consolidated statements of operations. We determine the fair value of our derivatives at the end of each reporting period based on quoted market prices from the NYMEX. We did not have any derivative instruments during the first six months of 2007.

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

Fixed Price and Price Cap Sales Contracts

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

From an accounting perspective, during periods of rising natural gas prices, our futures contracts have generally been marked-to-market through the recognition of a derivative asset and a corresponding derivative gain in our statements of operations. However, because our contracts to sell LNG or CNG to our customers at fixed prices or an index-based price that is subject to a fixed price cap are not derivatives for purposes of U.S. generally accepted accounting principles, a liability or a corresponding loss has not been recognized in our statements of operations during this historical period of rising natural gas prices for the future commitments under these contracts. As a result, our statements of operations do not reflect our firm commitments to deliver LNG or CNG at prices that are below, and in some cases, substantially below, the prevailing market price of natural gas (and therefore LNG or CNG).

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

	Estimated volumes(a)	Average price(b)		Contracts duration
CNG fixed price contracts	2,506,146	$	1.06	through 12/13
LNG fixed price contracts	21,609,891	$	0.37	through 7/09
CNG price cap contracts	5,720,949	$	0.87	through 12/09
LNG price cap contracts	10,751,067	$	0.57	through 12/08

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

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

December 31, 2004	$	3,646,338		to	$	4,456,636
December 31, 2005	$	15,148,070		to	$	18,514,308
December 31, 2006	$	(14,267,259	)	to	$	(17,437,761	)
Six months ended June 30, 2007	$	(351,281	)		$	(429,344	)

At June 30, 2007, we estimate we will incur between $7.0 million and $8.6 million to cover the increased price of natural gas above the inherent price of natural gas embedded in our customer’s fixed price and price cap contracts over the duration of the contracts. These estimates were based on natural gas futures prices on June 30, 2007, and these estimates may change based on future natural gas prices and may be significantly higher or lower.

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

July 1, 2007 through December 31, 2007		11,378,184
2008		14,670,803
2009		2,486,896
2010		230,000
2011		230,000
2012		230,000
2013		230,000

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

Income Taxes

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

Stock-Based Compensation

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

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

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

Impairment of Goodwill and Long-lived Assets

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

Recently Issued Accounting Pronouncements

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

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

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements (SFAS 157), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007 and all interim periods within those fiscal years. Earlier application is permitted provided that the reporting entity has not yet issued interim or annual financial statements for that fiscal year. We are currently evaluating the impact, if any, that SFAS 157 may have on our financial statements.

In February 2007, the FASB issued Statement of Financial Accounting Standard No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS 159). SFAS 159 permits entities to choose to measure certain financial instruments and other eligible items at fair value when the items are not otherwise currently required to be measured at fair value. Under SFAS 159, the decision to measure items at fair value is made at specified election dates on an irrevocable instrument-by-instrument basis. Entities electing the fair value option would be required to recognize changes in fair value in earnings and to expense upfront costs and fees associated with the item for which the fair value option is elected. Entities electing the fair value option are required to distinguish, on the face of the statement of financial position, the fair value of assets and liabilities for which the fair value option has been elected and similar assets and liabilities measured using another measurement attribute. If elected, SFAS 159 will be effective as of the beginning of the first fiscal year that begins after November 15, 2007, with earlier adoption permitted if all of the requirements of SFAS 157 are adopted. We are currently evaluating the impact, if any, that SFAS 159 may have on our financial statements.

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 June 30,				Six Months Ended June 30,
	2006		2007		2006		2007
Statement of Operations Data:
Revenue	100.0	%	100.0	%	100.0	%	100.0	%
Operating expenses:
Cost of sales	81.6	%	73.5	%	86.2	%	74.5	%
Derivative (gains) losses	0.0	%	0.0	%	0.7	%	0.0	%
Selling, general and administrative	20.4	%	34.0	%	21.8	%	28.5	%
Depreciation and amortization	6.5	%	5.5	%	6.1	%	5.6	%
Total operating expenses	108.4	%	113.1	%	114.8	%	108.6	%
Operating income (loss)	(8.4	)%	(13.1	)%	(14.8	)%	(8.6	)%

Interest (income), net	(1.1	)%	(1.8	)%	(1.0	)%	(1.4	)%
Other (income) expense, net .	(0.3	)%	0.2	%	(0.1	)%	0.3	%
Income (loss) before income taxes	(7.0	)%	(11.5	)%	(13.7	)%	(7.4	)%
Income tax expense (benefit)	(2.1	)%	0.2	%	(4.1	)%	0.1	%
Net income (loss)	(4.9	)%	(11.6	)%	(9.6	)%	(7.5	)%

Three Months Ended June 30, 2007 Compared to Three Months Ended June 30, 2006

Revenue. Revenue increased by $9.2 million to $30.7 million in the three months ended June 30, 2007, from $21.5 million in the three months ended June 30, 2006. This increase was primarily the result of an increase in the number of CNG and LNG gallons delivered from 16.9 million gasoline gallon equivalents in the second quarter of 2006 to 19.3 million gasoline gallon equivalents in the second quarter of 2007. One of our new transit customers (Long Island Bus, NY) and one of our new airport customers (Los Angeles International Airport shuttle busses) together accounted for 1.7 million gasoline gallon equivalents of the increase. The remaining increase in gasoline gallon equivalents delivered was due to the addition of other smaller new customers and growth from our existing customers. We also recorded $4.4 million of revenue related to fuel tax credits in the second quarter of 2007, which credits began in October 2006. Revenue also increased between periods due to a $1.4 million increase in station construction revenue between periods.

Cost of sales. Cost of sales increased by $4.9 million to $22.5 million in the three months ended June 30, 2007, from $17.6 million in the three months ended June 30, 2006. This increase was primarily the result of an increase in costs related to delivering more CNG and LNG between periods. Also adding to this increase was an increase in our effective cost per gallon between periods due to higher natural gas prices between periods. Our effective cost per gallon increased to $1.11 per gallon for the three months ended June 30, 2007, which represents a $.07 per gallon increase over the three months ended June 30, 2006. Also contributing to the increase in cost of sales between periods is a $1.1 million increase in costs related to construction activities during the three month period ended June 30, 2007.

Derivative (gains) losses. We did not generate any derivative gains or losses in the three month periods ended June 30, 2007 and 2006 as we did not own any derivative instruments during these periods.

Selling, general and administrative. Selling, general and administrative expenses increased by $6.0 million to $10.4 million in the three months ended June 30, 2007, from $4.4 million in the three months ended June 30, 2006. The increase was primarily related to recording $3.8 million of stock option expense in May and June of 2007 associated with stock options we granted to our employees in May 2007 upon the effectiveness of our registration statement on Form S-1 filed in connection with our initial public offering. In addition, salaries and benefits increased between periods by $1.0 million, primarily related to increased salaries and compensation due to our executive officers. Our marketing expenses increased $.4 million between periods, primarily due to certain advertising we conducted at the Ports of Los Angeles and Long Beach, and our bad debt expense increased $.2 million between periods as we provided a reserve against loans made to one of our vehicle financing customers during the three months ended June 30, 2007. Our business insurance costs also increased $.2 million between periods primarily due to an increase in premiums related to our directors’ and officers’ insurance between periods.

Depreciation and amortization. Depreciation and amortization increased by $0.3 million to $1.7 million in the three months ended June 30, 2007, from $1.4 million in the three months ended June 30, 2006. This increase was primarily the result of additional depreciation expense in the three months ended June 30, 2007 related to increased property and equipment balances between periods, primarily related to our station network and our fleet of LNG tanker trailers.

Interest (income) expense, net. Interest (income) expense, net, increased by $0.3 million from $0.2 million of income in the three months ended June 30, 2006, to $0.5 million of income for the three months ended June 30, 2007. This increase was primarily the result of an increase in interest income in the three months ended June 30, 2007 due to higher average cash balances on hand in the second quarter of 2007 associated with the proceeds received from our initial public offering.

Other (income) expense, net. Other (income) expense, net decreased by $123,000 from $67,000 of income in the three months ended June 30, 2006 to $56,000 of expense in the three months ended June 30, 2007. The decrease was primarily related to the costs related to station closures in the second quarter of 2007.

Six months Ended June 30, 2007 Compared to Six months Ended June 30, 2006

Revenue. Revenue increased by $16.2 million to $58.8 million in the six months ended June 30, 2007, from $42.6 million in the six months ended June 30, 2006. This increase was primarily the result of an increase in the number of CNG and LNG delivered from 32.5 million gasoline gallon equivalents in the first six months of 2006 to 37.1 million gasoline gallon equivalents in the first six months of 2007. One of our new transit customers (Long Island Bus, NY) and one of our new airport customers (Los Angeles International Airport shuttle busses) together accounted for 2.6 million gasoline gallon equivalents of the increase. The remaining increase in gasoline gallon equivalents delivered was due to the addition of other smaller new customers and growth from our existing customers. In the first six months of 2007, we recorded $8.2 million of revenue related to fuel tax credits, which credits began in October 2006. Revenue also increased between periods due to a $3.1 million increase in station construction revenue between periods.

Cost of sales. Cost of sales increased by $7.1 million to $43.8 million in the six months ended June 30, 2007, from $36.7 million in the six months ended June 30, 2006. This increase was primarily the result of an increase in costs related to delivering more CNG and LNG between periods. Also contributing to the increase in cost of sales between periods is a $2.8 million increase in costs related to construction activities during the six month period ended June 30, 2007.

Derivative (gains) losses. Derivative gains decreased by $0.3 million to $0.0 million in the six months ended June 30, 2007, from a loss of $0.3 million in the six months ended June 30, 2006. This decrease was primarily the result of the fact that we incurred a loss in the six month period ended June 30, 2006 when we liquidated certain futures contracts and we did not sell or own any futures contracts during the six month period ended June 30, 2007.

Selling, general and administrative. Selling, general and administrative expenses increased by $7.4 million to $16.7 million in the six months ended June 30, 2007, from $9.3 million in the six months ended June 30, 2006. The increase was primarily related to recording $3.8 million of stock option expense in May and June of 2007 associated with the stock options we granted to our employees in May 2007 upon the effectiveness of the registration statement on Form S-1 we filed in connection with our initial public offering. There was an increase of $1.5 million in salaries and benefits between periods primarily related to the increased compensation due to our executive officers and the hiring of additional employees. Our employee headcount increased from 91 at June 30, 2006 to 103 at June 30, 2007. In addition, our rent expense increased $.2 million between periods as we acquired additional office space between periods and our travel and entertainment expenses increased $.1 million between periods, primarily related to increased travel related to our sales team. Our marketing expenses increased $.6 million between periods, primarily due to certain advertising we conducted related to our refuse market segment and in the Ports of Los Angeles and Long Beach. Our bad debt expense increased $0.9 million between periods as we provided a reserve against loans made to a vehicle manufacturer and one of our vehicle financing customers during the six months ended June 30, 2007. Our business insurance costs also increased $0.2 million between periods, primarily due to premium increases in our directors’ and officers’ insurance between periods, our credit card fees increased $0.3 million between periods as more of our retail customers are using credit cards to purchase their fuel, and our audit and accounting fees increased $0.3 million between periods as we are incurring increased fees associated with being a public company.

Depreciation and amortization. Depreciation and amortization increased by $0.7 million to $3.3 million in the six months ended June 30, 2007, from $2.6 million in the six months ended June 30, 2006. This increase was primarily related to the result of additional depreciation expense in the six months ended June 30, 2007 related to increased property and equipment balances between periods, primarily related to our station network and our fleet of LNG tanker trailers.

Interest (income) expense, net. Interest (income) expense, net, increased by $0.4 million from $0.4 million of income in the six months ended June 30, 2006, to $0.8 million of income for the six months ended June 30, 2007. This increase was primarily the result of a decrease in interest expense in the six months ended June 30, 2007 due to the conversion of $4 million of convertible notes in April 2006 which eliminated the interest expense on these notes. In addition, interest income for the six months ended June 30, 2007 increased in comparison to the six month period ended June 30, 2006 due to higher average cash balances on hand in the first six months of 2007 associated with the proceeds received from our initial public offering.

Other (income) expense, net. Other (income) expense, net decreased by $221,000 from $42,000 of income in the six months ended June 30, 2006 to $179,000 of expense in the six months ended June 30, 2007. The decrease was primarily related to costs related to station closures in the second quarter of 2007.

Seasonality and Inflation

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

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

Liquidity and Capital Resources

Historically, our principal sources of liquidity have consisted of cash provided by operations and financing activities, cash and cash equivalents, the issuance of common stock, sometimes in association with the exercise of certain warrants that were callable at our option, and in 2006, a revolving line of credit with Boone Pickens, our majority stockholder. In May 2007, we completed our initial public offering of 10,000,000 shares of common stock at a public offering price of $12.00 per share. Net cash proceeds from the initial public offering were approximately $108.6 million, after deducting underwriting discounts, commissions and offering expenses. In addition to funding operations, our principal uses of cash have been, and are expected to be, the construction of new fueling stations, the construction of a new LNG liquefaction plant in California, the purchase of new LNG tanker trailers, the financing of natural gas vehicles for our customers, and general corporate purposes, including making deposits to support our derivative activities, geographic expansion (domestically and internationally), expanding our sales and marketing activities, and for working capital for our expansion. We financed our operations in the first six months of 2007 primarily through cash provided by operations and financing activities. At June 30, 2007, we had total cash and cash equivalents of $111.0 million compared to $0.9 million at December 31, 2006.

Cash provided by operating activities was $16.8 million for the six months ended June 30, 2007 compared to cash used in operating activities of $8.6 million for the six months ended June 30, 2006. The increase in operating cash flow was primarily due to the collection of a $22.9 million receivable that was generated on December 28, 2006 when we transferred certain futures contracts to Boone Pickens. Also adding to the operating cash flow increase between periods was a $6.2 million reduction of income tax payments between periods. Offsetting these increases was the collection of $8.7 million of cash in the first six months of 2006 when we sold certain derivative positions. We did not have any futures contracts outstanding during the first six months of 2007.

Cash used in investing activities was $17.0 million for the six months ended June 30, 2007, compared to $6.7 million for the six months ended June 30, 2006. The $10.3 million increase between periods was primarily due to increased purchases of property and equipment and increased construction in progress activity in the first six months of 2007, including $8.1 million that we spent on developing our LNG liquefaction plant in California.

Cash provided by financing activities for the six months ended June 30, 2007 was $110.3 million, compared to cash provided by financing activities of $21.7 million for the six months ended June 30, 2006. The $88.6 million increase between periods is attributable primarily to net proceeds of $110.3 million from our initial public offering which closed in May 2007.

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

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

Capital Expenditures

We expect to make capital expenditures, net of grant proceeds, of approximately $17.8 million in 2007 to construct new natural gas fueling stations, purchase LNG tanker trailers, and for general corporate purposes. Additionally, we have budgeted approximately $50 to $55 million over the course of 2007 and 2008 to construct an LNG liquefaction plant in California which we are in the initial stages of building and anticipate will be operational in the summer of 2008. We also anticipate using $15 to $20 million from the proceeds of our initial public offering to finance the purchase of natural gas vehicles by our customers.

Contractual Obligations

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

	Payments Due by Period
Contractual Obligations:	Total		Remainder of 2007		2008 and 2009		2010 and 2011		2012 and beyond
Capital lease obligations(a)	$	254,363	$	29,466	$	133,691	$	91,206	$	0
Operating lease commitments(b)	5,277,278		651,683		2,361,130		1,349,217		915,248
“Take or Pay” LNG purchase contracts(c)	2,607,500		1,303,750		1,303,750		0		0
Construction contracts(d)	4,407,000		4,407,000		0		0		0
Other long-term contract liabilities(e)	26,809,561		18,047,311		8,762,250		0		0

Total	$	39,355,702	$	24,439,210	$	12,560,821	$	1,440,423	$	915,248

(a) Consists of obligations under a lease of capital equipment used to finance such equipment. Amounts do not include interest as they are not material.

(b) Consists of various space and ground leases for our offices and fueling stations as well as leases for equipment.

(c) The amounts in the table represent our estimates for our fixed LNG purchase commitments under two “take or pay” contracts.

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

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

Off-Balance Sheet Arrangements

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

· outstanding standby letters of credit totaling $0.1 million,

· outstanding surety bonds for construction contracts and general corporate purposes totaling $5.2 million,

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

· operating leases where we are the lessee,

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

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

We provide standby letters of credit primarily to support facility leases and surety bonds primarily for construction contracts in the ordinary course of business, as a form of guarantee. No liability has been recorded in connection with standby letters of credit or surety bonds as we do not believe, based on historical experience and information currently available, that it is probable that any amounts will be required to be paid under these arrangements.

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

We have entered into operating lease arrangements for certain equipment and for our office and field operating locations in the ordinary course of business. The terms of our leases expire at various dates through 2016. Additionally, in November 2006, we entered into a ground lease for 36 acres in California on which we are in the initial stages of building an LNG liquefaction plant. We have budgeted approximately $50 to $55 million over the course of 2007 and 2008 to construct this plant. The lease is for an initial term of 30 years, beginning on the date that the plant commences operations, and requires annual base rent payments of $230,000 per year, plus $130,000 per year for each 30,000,000 gallons of production capacity, subject to future adjustment based on consumer price index changes. We must also pay a royalty to the landlord for each gallon of LNG produced at the facility, as well as for certain other services that the landlord will provide. Our obligations under the lease are contingent on us obtaining the necessary permits and approvals required in the lease related to the construction and operation of the LNG liquefaction plant, which are in process. As the payments are contingent obligations, they are not included in “Operating Lease Commitments” in the “Contractual Obligations” table set forth above.

We are also the lessor in various leases with our customers, whereby our customers lease from us certain stations and equipment that we own. The leases generally qualify as sales-type leases for accounting purposes, which result in our customers, the lessees, reflecting the property and equipment on their balance sheets.

Item 3. – Quantitative and Qualitative Disclosures About Market Risk

Commodity Risk We are subject to market risk with respect to our sales of natural gas, which has historically been subject to volatile market conditions. Our exposure to market risk is heightened when we have a fixed price or price cap sales contract with a customer that is not covered by a futures contract, or when we are otherwise unable to pass through natural gas price increases to customers. Natural gas prices and availability are affected by many factors, including weather conditions, overall economic conditions and foreign and domestic governmental regulation and relations.

Natural gas costs represented 63% of our cost of sales for 2006 and 59% of our cost of sales for the six months ended June 30, 2007. Prices for natural gas over the seven-year and six month period from December 31, 1999 through June 30, 2007, based on the NYMEX daily futures data, has ranged from a low of $1.65 per Mcf to a high of $19.38 per Mcf. At June 30, 2007, the NYMEX index price of natural gas was $7.59 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 No. 133, Accounting for Derivative Instruments and Hedging Activities. Under this standard, the accounting for changes in the fair value of a derivative depends upon whether it has been designated in a hedging relationship and, further, on the type of hedging relationship. To qualify for designation in a hedging relationship, specific criteria must be met and appropriate documentation maintained. Our futures contracts did not qualify for hedge accounting under SFAS No. 133 for the years ended December 31, 2004, 2005 and 2006, and changes in the fair value of the derivatives were recorded directly to our consolidated statements of operations at the end of each reporting period. We did not own any derivative instruments during the first six months of 2007.

The fair value of the futures contracts we use is based on quoted prices in active exchange traded or over the counter markets. The fair value of these futures contracts is continually subject to change due to changing market conditions. The net effect of the realized and unrealized gains and losses related to these derivative instruments for the year ended December 31, 2006 was a $79.0 million decrease to pre-tax income. We did not have any futures contracts outstanding during the three or six month periods ended June 30, 2007. In an effort to mitigate the volatility in our earnings related to futures activities, in

February 2007, our board of directors adopted a revised natural gas hedging policy which restricts our ability to purchase natural gas futures contracts and offer fixed-price sales contracts to our customers. We plan to structure prospective futures contracts so that they will be accounted for as cash flow hedges under SFAS No. 133, but we cannot be certain they will qualify. For more information, please read “—Risk Management Activities” above.

We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to our fixed price and price cap sales contracts as of June 30, 2007. Market risk is estimated as the potential loss resulting from a hypothetical 10.0% adverse change in the fair value of natural gas prices. The results of this analysis, which assumes natural gas prices are in excess of our customer’s price cap arrangements, and may differ from actual results, are as follows:

	Hypothetical adverse change in price		Change in annual pre- tax income
			(in millions)
Fixed price contracts	10.0	%	$	(1.6	)
Price cap contracts	10.0	%	$	(1.2	)

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

Item 4. – Controls and Procedures

Disclosure Controls and Procedures

We maintain disclosure controls and procedures and internal controls that are designed to provide reasonable, but not absolute, assurance that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. We carried out an evaluation, under the supervision of and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report. Based on the foregoing, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

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

PART II. – OTHER INFORMATION

Item 1. – Legal Proceedings

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

Item 1A. – Risk Factors

Investing in our common stock involves a high degree of risk. You should carefully consider the following risk factors, as well as the other information in this report, before deciding whether to invest in shares of our common stock. The occurrence of any of the following risks could harm our business, financial condition, results of operations and/or growth prospects. In that case, the trading price of our common stock could decline, and you may lose all or part of your investment.

Risks Related to Our Business and Industry

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

In 2006 and the first six months of 2007, we incurred pre-tax losses of $10.8 million and $4.4 million, respectively, related to our operations, which consist of natural gas fueling activities and station operations, and derivative losses of $79.0 million and $0.0 million, respectively, combining for overall pre-tax losses of $89.8 million and $4.4 million, respectively. In 2004 and 2005, excluding derivative gains, we incurred pre-tax losses of $6.8 million and $15.2 million, respectively, related to our operations. We must continue to invest in developing the natural gas vehicle fuel market, and we cannot assure you that our natural gas sales activities and station operations will achieve or maintain profitability. If our natural gas sales activities and station operations continue to lose money, our business will suffer.

We historically have relied on capital contributions by related parties, particularly by Boone Pickens, and such capital may not be available in the future.

For the fiscal years ended December 31, 2004, 2005 and 2006, Boone Pickens and an affiliated trust made cash investments of $1.9 million, $12.0 million and $18.0 million, respectively, in our company. In August 2006, we entered into a $50 million revolving line of credit with Mr. Pickens to fund margin calls related to our futures contracts. This line of credit was increased to $100 million in November 2006. In December 2006, Mr. Pickens cancelled all amounts we owed to him under this line of credit (approximately $69.7 million) and assumed all of our outstanding futures contracts, together with all associated liabilities and obligations (approximately $78.7 million), in exchange for (1) the issuance to Mr. Pickens of a five-year warrant to purchase up to 15,000,000 shares of our common stock at $10.00 per share (which warrant was valued at $80.9 million), and (2) the assignment to Mr. Pickens of any refunds of margin deposits related to the assumed futures contracts that were made using money borrowed under the line of credit. Additionally, for the fiscal years ended December 31, 2004, 2005 and 2006, Perseus ENRG Expansion, L.L.C. and a related fund invested $3.0 million, $2.0 million and $3.0 million, respectively, in our company. We may not be able to obtain capital from related parties in the future. None of our officers, directors or stockholders (or their respective affiliates) are under any obligation to continue to provide cash to meet our future liquidity needs. If capital is unavailable to us in the future from related parties or from other persons on terms favorable to us, our ability to continue to support our business growth and to respond to business challenges could be significantly limited.

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 to the end of 2006, the price for natural gas, based on the NYMEX daily futures data, ranged from a low of $1.65 per Mcf to a high of $19.38 per Mcf. As of June 30, 2007, the NYMEX index price for natural gas was $7.59 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 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.

The infrastructure to support gasoline and diesel consumption is vastly more developed than the infrastructure for natural gas vehicle fuels.

Gasoline and diesel fueling stations and service infrastructure are widely available in the United States. For natural gas vehicle fuels to achieve more widespread use in the United States and Canada, they will require a promotional and educational effort, and the development and supply of more natural gas vehicles and fueling stations. This will require significant continued effort by us, as well as government and clean air groups, and we may face resistance from oil companies and other vehicle fuel companies. There is no assurance natural gas will ever achieve the level of acceptance as a vehicle fuel necessary for us to expand our business significantly.

A decline in the demand for vehicular natural gas will reduce our revenue and negatively affect our ability to sustain and grow our operations.

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 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. In that event, our growth would be slowed and our business would suffer.

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. 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.

There are a small number of companies that convert vehicles to operate on natural gas, which may restrict our sales.

Conversion of vehicle engines from gasoline or diesel to natural gas is performed only by a small number of vehicle conversion suppliers that must meet stringent safety and engine emissions certification standards. The engine certification process is time consuming and expensive and raises vehicle costs. Without an increase in vehicle conversion, vehicle choices for fleet use will remain limited and our sales may be restricted, even if there is demand.

If there are advances in other alternative vehicle fuels or technologies, or if there are improvements in gasoline, diesel or hybrid engines, demand for natural gas vehicles may decline and our business may suffer.

Technological advances in the production, delivery and use of alternative fuels that are, or are perceived to be, cleaner, more cost-effective or more readily available than CNG or LNG have the potential to slow adoption of natural gas vehicles. Advances in gasoline and diesel engine technology, especially hybrids, may offer a cleaner, cost-effective option and make fleet customers less likely to convert their fleets to natural gas. Technological advances related to ethanol or biodiesel, which are increasingly used as an additive to, or substitute for, gasoline and diesel, may slow the need to diversify fuels and impact the growth of the natural gas vehicle market. In addition, hybrid, electric, hydrogen, and other alternative fuels in experimental or developmental stages may eventually offer a cleaner, more cost-effective alternative to gasoline and diesel than natural gas. Advances in technology which slow the growth of or conversion to natural gas vehicles or which otherwise reduce demand for natural gas as a vehicle fuel will have an adverse effect on our business. Failure of natural gas vehicle technology to advance at a sufficient pace may also limit its adoption and ability to compete with other alternative fuels.

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 source 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 built. 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.

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

Two third-party LNG suppliers supplied approximately 64% of the LNG we sold for the year ended December 31, 2006 and 51% for the six months ended June 30, 2007. Our contracts with these LNG suppliers generally may be terminated by the supplier on short notice. In particular, our supply agreement with Williams Gas Processing Company, which supplied 47% and 36% of our LNG for the year ended December 31, 2006 and for the six months ended June 30, 2007, respectively, can be terminated by Williams effective June 1, 2007 and expires on June 30, 2008. In addition, under certain circumstances, Williams 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 17% of our LNG for the year ended December 31, 2006 and 14% for the six months ended June 30, 2007, expires on June 30, 2008. We may be unable to renew these fueling contracts. 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 supply interruptions were to occur, our ability to meet customer demand would 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.

Our growth depends in part on environmental regulations 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 in the United States that promote or mandate the use of cleaner burning fuels, including natural gas for vehicles. 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. The delay, repeal or modification of federal or state policies and regulations that encourage the use of cleaner vehicles 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 in September 2009. Based on the service relationship we have with our customers, either we or our customers are able to claim the credit. 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 could slow and our business and results of operations could be adversely affected.

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. 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.

Oil companies and natural gas utilities, which have far greater resources and brand awareness than we have, may expand into the natural gas fuel market, which could harm our business and prospects.

There are numerous potential competitors who could enter the market for CNG and LNG as vehicle fuels. Many of these potential entrants, such as integrated oil companies and natural gas utilities, have far greater resources and brand awareness than we have. If the use of natural gas vehicles increases, these companies may find it more attractive to enter the market for natural gas vehicle fuels and we may experience increased pricing pressure, reduced operating margins and fewer expansion opportunities.

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 initial stages of designing and 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. If the new plant has higher than expected construction or 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.

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

From 2004 to 2006, we sold and delivered approximately 30 percent 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 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. 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 June 30, 2007, we were not economically hedged with respect to any of the anticipated requirements of our fixed price contracts, having sold the related futures contracts which we previously held. Based on natural gas prices as of June 30, 2007, we estimate we will incur between $7.0 million to $8.6 million to cover the increased price of natural gas above the inherent price of natural gas embedded in our customer’s fixed price and price cap contracts over the duration of the contracts.

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 or price cap customer contracts when determining the volumes included in the futures contracts we purchase. 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 you 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 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. 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.

Boone Pickens cancelled his guarantee of our futures contracts which will require us to make significantly larger initial margin deposits when we purchase futures contracts. This will adversely affect our cash flows, and we may be unable to secure these contracts on terms that are favorable or affordable to us or at all.

Historically, we have purchased all of our natural gas futures contracts through Sempra Energy Trading Corp. We did not have any futures contracts outstanding at June 30, 2007. Our past obligations under our contract with Sempra were guaranteed by Boone Pickens. Mr. Pickens is our largest stockholder, a director and the principal of BP Capital, L.P., which advises us regarding our hedging activities. As Mr. Pickens cancelled his guarantee with Sempra in March 2007, Sempra may cancel our contract with them at any time. Without Mr. Pickens’ guarantee, we expect to have significantly larger requirements for upfront margin deposits, on the order of up to fifteen times greater than current deposit requirements. We also anticipate that it will be more difficult to purchase futures contracts generally (i.e., through Sempra or other third parties) without his guarantee. If we cannot enter into futures contracts, our ability to offer fixed price supply contracts to our customers may be impaired and we will become more susceptible to price fluctuations and losses if this were to occur.

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, 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 No. 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 for the three months ended September 30, 2005 and experienced derivative losses of $19.9 million, $0.3 million, $65.0 million and $13.7 million for the three months ended December 31, 2005, March 31, 2006, September 30, 2006 and December 31, 2006, respectively. We had no derivative gains or losses for the three months ended June 30, 2006, March 31, 2007 or June 30, 2007. 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.

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. 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, 2006 and the six months ended June 30, 2007, sales in California accounted for approximately 38% and 40%, respectively and sales in Arizona accounted for approximately 23% and 21%, respectively, of the total amount of gallons we delivered. A 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.

Our finance and leasing activities may be unsuccessful due to competitive pressures.

The fleet financing and leasing marketplace is competitive and dominated by large finance companies. These companies may have greater financial resources than we do, offer more attractive rates to customers, finance other types of vehicles and equipment and offer a wider range of financial services to the customer. If these large finance companies do not finance natural gas vehicles and if potential customers prefer to work with these companies, our business may be disadvantaged.

We may incur losses and use working capital if we have to purchase vehicles that we intend to place with customers.

To ensure availability for our customers, we from time to time 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 their delivery to us, we may be unable to locate purchasers timely 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 June 30, 2007, we had approximately $9.5 million of vehicles under binding purchase agreements, of which $3.1 million had been paid at June 30, 2007, without corresponding customer orders.

If we are unable to attract, retain and motivate our executives and other key personnel our business would be harmed.

Our ability to manage and expand our business depends significantly on the skills and services of our management team, each of whom may terminate his or her service with us at any time and none of whom are subject to non-compete restrictions. We believe the loss of one or more members of our management team would harm our business because few people have comparable experience working in the natural gas vehicle industry or managing companies similar to ours. Moreover, we intend to grow our operations and to do so we will need to hire additional personnel in all areas of our business, particularly in sales and marketing. Competition for qualified personnel is intense, and we therefore may be unable to attract or retain qualified personnel and expand our business as planned.

We rely on related parties for advice regarding our derivative activities, and this advice may not be available to us in the future.

We depend upon Boone Pickens and his firm, BP Capital, L.P., for advice regarding energy markets and derivative activities. We cannot guarantee that we will be able to retain these services for any period of time. BP Capital may terminate its investment advisory agreement with us at any time upon 30 days written notice to us.

We may have difficulty managing our planned growth.

If we grow our business as planned, our management team and our operational, financial and accounting systems will also need to be expanded. This expansion would result in increased expenses and may strain our resources. If we are unable to manage this growth, we may experience higher expenses, poor internal controls, employee attrition and customer dissatisfaction, any of which could harm our business. Additionally, we may find it difficult to maintain important aspects of our corporate culture, which could negatively affect our ability to retain and recruit personnel, and otherwise adversely affect our future success.

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, we need to apply for 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.

The requirements of being a public company, including the costs of complying with Section 404 of the Sarbanes-Oxley Act of 2002, may strain our resources and distract management.

As a public company, we are incurring significant legal, accounting and other expenses that we did not incur as a private company. The Sarbanes-Oxley Act, as well as rules subsequently implemented by the SEC, NASDAQ and stock exchanges have required changes in corporate governance practices of public companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make some activities more time-consuming and costly. For example, as a result of becoming a public company, we have created additional board committees and have implemented a number of new corporate policies. In addition, we are incurring additional costs associated with our public company reporting. We also expect these new rules to make it more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage.

Ensuring that we have adequate financial and accounting controls to produce accurate financial statements on a timely basis is a costly and time-consuming effort that needs to be re-evaluated frequently. We will need to begin the process of documenting, reviewing and improving our internal controls in order to comply with Section 404 of the Sarbanes-Oxley Act of 2002, which requires management assessments of the effectiveness of our internal controls over financial reporting and a report by our independent registered public accounting firm addressing these assessments. Both we and our independent registered public accounting firm will be testing our internal controls in connection with the Section 404 requirements and, as part of that documentation and testing, identify areas for further attention and improvement. Improving our internal controls will likely involve substantial costs and take a significant time to complete, 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 independent registered public accounting firm identified certain internal controls over financial reporting that we will need to strengthen in connection with being a public company, and we have not yet implemented all the requested improvements. Specifically, we will need to automate several of our processes, hire additional personnel with finance and accounting expertise and add additional policies and procedures to bolster our control and disclosure environments. Hiring qualified employees is challenging, and we may be unable to find the people with the skill sets we require in a timely manner. Modifying and changing systems and procedures is also challenging, and new systems or procedures may not prove to be efficient and effective once they are in place. Our accounting and financial reporting department may not have all of the necessary resources to ensure that we will not have significant deficiencies or material weaknesses in our system of internal control over financial reporting. The effectiveness of our internal control over financial reporting may be limited by a variety of factors including: faulty human judgment and errors, omissions or mistakes; inappropriate management override of policies and procedures; and the possibility that any enhancements to disclosure controls and procedures may still not be adequate to assure timely and accurate financial information.

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 $3.0 million, $1.1 million, $41.2 million, $32.2 million, $0.9 million and $3.6 million for the three months ended March 31, 2006, June 30, 2006, September 30, 2006, December 31, 2006, March 31, 2007 and June 30, 2007, respectively. 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 gain 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.

There may not be a viable public market for our common stock.

Our common stock had not been publicly traded before our initial public offering, which was completed in May 2007. If an active trading market is not sustained, it may be difficult for you to sell your shares of stock at an attractive price or at all. It is possible that, in future quarters, our operating results may be below the expectations of securities analysts or investors. As a result of these and other factors, the price of our stock may decline, possibly materially.

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.

At June 30, 2007, 44,193,411 shares of our common stock were outstanding. Of these shares, only the 10,000,000 shares of our common stock sold in our initial public offering are freely tradable, without restriction, in the public market. Additionally, our directors, executive officers and certain principal stockholders have agreed to enter into “lock up” agreements with the underwriters of our initial public offering, in which they agreed to refrain from selling their shares for a period of 180 days after such offering. The lock-up is subject to extension under certain circumstances. After the lock-up

agreements pertaining to this offering expire, up to an additional 34,193,411 currently outstanding shares will be eligible for sale in the public market, 28,545,041 of which are held by directors, executive officers and other affiliates and will be subject to volume limitations under Rule 144 under the Securities Act of 1933, and various vesting agreements. If our existing stockholders sell, or indicate an intention to sell, substantial amounts of our common stock in the public market after the contractual lock-up and other legal restrictions on resale discussed in this report lapse, the trading price of our common stock could decline. WR Hambrecht + Co may, in its sole discretion, permit our directors, officers, employees and current stockholders who are subject to the 180-day contractual lock-up to sell shares prior to the expiration of the lock-up agreements.

In addition, as of June 30, 2007, there were 20,187,500 shares underlying options and warrants that were issued and outstanding. These shares will become eligible for sale in the public market to the extent permitted by the provisions of various option and warrant agreements, the lock-up agreements and Rules 144 and 701 under the Securities Act. 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.

We have also filed a registration statement on Form S-8 under the Securities Act covering shares of common stock reserved for issuance under our equity incentive plans. Upon such filing, shares of common stock issued upon the exercise of options under our equity incentive plans are available for sale in the public market, subject to Rule 144 volume limitations applicable to affiliates and subject to the lock-up agreements described above.

If securities analysts do not publish research or reports about our business, or if they downgrade our stock, the price of our stock could decline.

The trading market for our stock will rely in part on the availability of research and reports that third-party industry or financial analysts publish about us. Further, if one or more of the analysts who do cover us downgrade our stock, our stock price may decline. If one or more of these analysts cease coverage of our company, we could lose visibility in the market, which in turn could cause our stock price to decline.

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 June 30, 2007, Boone Pickens and affiliates (including Madeleine Pickens, his wife) beneficially owned in the aggregate approximately 60.0% 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, concentration may facilitate a change in control at a time when you and other investors may prefer not to sell.

Provisions in our certificate of incorporation and bylaws and Delaware law may discourage, delay or prevent a change of control of our company or changes in our management and, therefore, depress the trading price of our stock.

Our certificate of incorporation and bylaws contain provisions that could depress the trading price of our stock by acting to discourage, delay or prevent a change of control of our company or changes in our management that the stockholders of our company may deem advantageous. These provisions:

· authorize the issuance of “blank check” preferred stock that our board of directors could issue to increase the number of outstanding shares to discourage a takeover attempt,

· provide that a special meeting of stockholders may only be called by our board of directors or our chief executive officer,

· provide that the board of directors is expressly authorized to make, alter or repeal our bylaws, and

· establish advance notice requirements for nominations for elections to our board of directors or for proposing matters that can be acted upon by stockholders at stockholder meetings.

Additionally, we are subject to Section 203 of the Delaware General Corporation Law, which generally prohibits a Delaware corporation from engaging in any of a broad range of business combinations with any “interested” stockholder for a period of three years following the date on which the stockholder became an “interested” stockholder and which may discourage, delay or prevent a change of control of our company.

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. 333-139496) that was declared effective by the Securities and Exchange Commission on May 24, 2007. On May 31, 2007, 10,000,000 shares of common stock were sold on our behalf at an initial public offering price of $12.00 per share (for aggregate gross offering proceeds of $120.0 million) managed by W.R. Hambrecht + Co., LLC, Simmons & Company International, Susquehanna Financial Group, LLP, and NBF Securities (USA) Corp. In addition, on June 22, 2007, in connection with the exercise of the underwriters’ over-allotment option, 1,500,000 additional shares of common stock were sold by selling stockholders at the initial public offering price of $12.00 per share (for aggregate gross offering proceeds of $18.0 million). We received no proceeds from the sale of shares by selling stockholders. The offering terminated following the closing of the over-allotment sale.

We paid to the underwriters underwriting discounts totaling approximately $7.0 million in connection with the offering. In addition, through June 30, 2007, we incurred additional costs of approximately $4.4 million in connection with the offering, which when added to the underwriting discounts paid by us, amounts to total expenses of approximately $11.4 million. Thus, the net offering proceeds to us, after deducting underwriting discounts and offering expenses, were approximately $108.6 million through June 30, 2007. No offering expenses were paid directly or indirectly to any of our directors or officers (or their associates) or persons owning ten percent or more of any class of our equity securities or to any other affiliates.

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

· construction of our LNG liquefaction plant in California ($.7 million),

· construction and installation of CNG and LNG stations ($1.5 million),

· financing customer vehicle purchases ($.6 million), and

· working capital ($.6 million).

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

Item 3. – Defaults upon Senior Securities

None.

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

None.

Item 5. – Other Information

None.

Item 6. – Exhibits

(a) Exhibits

10.1		Underwriting Agreement dated May 31, 2007

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.

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: August 14, 2007	By:	/s/	Richard R. Wheeler
			Richard R. Wheeler
			Chief Financial Officer (Principal Financial Officer and duly authorized to sign on behalf of the registrant)