Clean Energy Fuels Corp. - Quarter Report: 2011 June (Form 10-Q)

Table of Contents

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, 2011

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 400, Seal Beach CA 90740

(Address of principal executive offices, including zip code)

(562) 493-2804

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232,405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

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

Large accelerated filer o		Accelerated filer x

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

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 2, 2011, there were 70,368,655 shares of the registrant’s common stock, par value $0.0001 per share, issued and outstanding.

Table of Contents

CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

INDEX

Table of Contents

PART I.—FINANCIAL INFORMATION
Item 1.—Financial Statements (Unaudited)	3
Item 2.—Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3.—Quantitative and Qualitative Disclosures About Market Risk	31
Item 4.—Controls and Procedures	32
PART II.—OTHER INFORMATION
Item 1.—Legal Proceedings	33
Item 1A.—Risk Factors	33
Item 2.—Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 3.—Defaults upon Senior Securities	45
Item 4.—(Removed and Reserved)	45
Item 5.—Other Information	45
Item 6.—Exhibits	46

Table of Contents

PART I.—FINANCIAL INFORMATION

Item 1.—Financial Statements (Unaudited)

Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Balance Sheets

December 31, 2010 and June 30, 2011 (Unaudited)

(In thousands, except share data)

	December 31, 2010			June 30, 2011
Assets
Current assets:
Cash and cash equivalents	$	55,194		$	35,276
Restricted cash	2,500			6,869
Accounts receivable, net of allowance for doubtful accounts of $702 and $764 as of December 31, 2010 and June 30, 2011, respectively	45,645			36,628
Other receivables	27,280			17,397
Inventory, net	20,483			29,435
Prepaid expenses and other current assets	10,959			12,889
Total current assets	162,061			138,494
Land, property and equipment, net	211,643			229,074
Notes receivable and other long-term assets	15,059			37,910
Investments in other entities	10,748			14,773
Goodwill	71,814			71,814
Intangible assets, net	112,174			106,824
Total assets	$	583,499		$	598,889
Liabilities and Stockholders’ Equity
Current liabilities:
Current portion of long-term debt and capital lease obligations	$	22,712		$	23,941
Accounts payable	28,635			26,569
Accrued liabilities	28,137			29,419
Deferred revenue	17,507			12,308
Total current liabilities	96,991			92,237
Long-term debt and capital lease obligations, less current portion	41,704			66,051
Other long-term liabilities	28,588			23,502
Total liabilities	167,283			181,790
Commitments and contingencies (Note 15)
Stockholders’ equity:
Preferred stock, $0.0001 par value. Authorized 1,000,000 shares; issued and outstanding no shares	—			—
Common stock, $0.0001 par value. Authorized 149,000,000 shares; issued and outstanding 69,610,098 shares and 70,317,747 shares at December 31, 2010 and June 30, 2011, respectively	7			7
Additional paid-in capital	569,202			584,367
Accumulated deficit	(151,926		)	(167,297		)
Accumulated other comprehensive loss	(3,996		)	(3,481		)
Total Clean Energy Fuels Corp. stockholders’ equity	413,287			413,596
Noncontrolling interest in subsidiary	2,929			3,503
Total stockholders’ equity	416,216			417,099
Total liabilities and stockholders’ equity	$	583,499		$	598,889

See accompanying notes to condensed consolidated financial statements.

Table of Contents

Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Statements of Operations

For the Three Months and Six Months Ended June 30, 2010 and 2011

(Unaudited)

(In thousands, except share and per share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2011			2010			2011
Revenue:
Product revenues	$	39,434		$	61,523		$	73,706		$	120,055
Service revenues	4,601			7,590			9,317			14,399
Total revenues	44,035			69,113			83,023			134,454
Operating expenses:
Cost of sales:
Product cost of sales	28,692			46,888			54,189			90,737
Service cost of sales	1,923			3,536			3,986			6,690
Derivative (gains) losses:
Series I warrant valuation	(16,615		)	(4,835		)	1,989			(1,535		)
Selling, general and administrative	14,878			21,653			28,527			39,683
Depreciation and amortization	5,070			7,632			10,060			14,842
Total operating expenses	33,948			74,874			98,751			150,417
Operating income (loss)	10,087			(5,761		)	(15,728		)	(15,963		)
Interest income (expense), net	(22		)	(1,506		)	87			(2,327		)
Other income (expense), net	(38		)	187			4			788
Income from equity method investments	28			164			105			375
Income (loss) before income taxes	10,055			(6,916		)	(15,532		)	(17,127		)
Income tax (expense) benefit	(77		)	1,177			1,127			1,912
Net income (loss)	9,978			(5,739		)	(14,405		)	(15,215		)
Income (loss) of noncontrolling interest	(83		)	120			(67		)	(157		)
Net income (loss) attributable to Clean Energy Fuels Corp.	$	9,895		$	(5,619	)	$	(14,472	)	$	(15,372	)
Income (loss) per share attributable to Clean Energy Fuels Corp.
Basic	$	0.16		$	(0.08	)	$	(0.24	)	$	(0.22	)
Diluted	$	0.14		$	(0.08	)	$	(0.24	)	$	(0.22	)
Weighted average common shares outstanding
Basic	60,876,741			70,302,782			60,494,148			70,199,963
Diluted	71,859,875			70,302,782			60,494,148			70,199,963

See accompanying notes to condensed consolidated financial statements.

Table of Contents

Clean Energy Fuels Corp.

Condensed Consolidated Statements of Cash Flows

For the Six Months Ended June 30, 2010 and 2011

(Unaudited)

(In thousands)

	Six Months Ended June 30,
	2010			2011
Cash flows from operating activities:
Net loss	$	(14,405	)	$	(15,215	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization	10,060			14,842
Provision for doubtful accounts, notes receivables and inventory	139			255
Derivative loss (gain)	1,989			(1,535		)
Stock-based compensation expense	5,962			6,932
Accretion of notes payable	—			1,388
Amortization of debt issuance cost	—			114
Loss (gain) on contingent consideration for acquisitions	500			(700		)
Changes in operating assets and liabilities, net of assets and liabilities acquired:
Accounts and other receivables	(6,679		)	18,595
Inventory	(1,664		)	(9,004		)
Margin deposits on futures contracts	(2,205		)	2,981
Prepaid expenses and other assets	(177		)	(2,940		)
Accounts payable	69			(2,066		)
Accrued expenses and other	2,380			(3,761		)
Net cash provided by (used in) operating activities	(4,031		)	9,886
Cash flows from investing activities:
Purchases of property and equipment	(17,419		)	(27,585		)
Proceeds from sale of property and equipment	67			—
Proceeds from sale of loans receivable	276			—
Restricted cash related to DCEMB bond offering and letters of credit	—			(27,413		)
Contingent consideration paid relating to business acquisitions	—			(2,159		)
Investments in other entities	(539		)	(2,700		)
Net cash used in investing activities	(17,615		)	(59,857		)
Cash flows from financing activities:
Proceeds from issuance of common stock and exercise of stock options	10,535			733
Proceeds from capital lease obligations and debt instruments	—			41,850
Proceeds from revolving line of credit	—			21,945
Proceeds from minority interest DCE equity contribution	—			417
Payments for debt issuance costs	—			(1,767		)
Repayment of borrowing under revolving line of credit	—			(16,665		)
Repayment of capital lease obligations and debt instruments	(275		)	(15,497		)
Net cash provided by financing activities	10,260			31,016
Effect of exchange rates on cash and cash equivalents	—			(963		)
Net decrease in cash	(11,386		)	(19,918		)
Cash, beginning of period	67,087			55,194
Cash, end of period	$	55,701		$	35,276
Supplemental disclosure of cash flow information:
Income taxes paid	$	216		$	266
Interest paid, net of approximately $180 and $125 capitalized, respectively	297			714

See accompanying notes to condensed consolidated financial statements.

Table of Contents

Clean Energy Fuels Corp. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(In thousands, except share data)

Note 1—General

Nature of Business: Clean Energy Fuels Corp., together with its majority and wholly owned subsidiaries (hereinafter collectively referred to as the “Company”), is engaged in the business of selling natural gas fueling solutions to its customers, primarily in the United States. Beginning September 7, 2010 with its acquisition of I.M.W. Industries, Ltd. (“IMW”), the Company began selling certain equipment and services internationally. The Company has a broad customer base in a variety of markets, including public transit, refuse, airports and regional trucking. The Company operates, maintains or supplies approximately 248 natural gas fueling locations in Arizona, California, Colorado, Connecticut, Florida, Georgia, Idaho, Illinois, Maryland, Massachusetts, Nevada, New Jersey, New Mexico, New York, Ohio, Oklahoma, Rhode Island, Texas, Virginia, Washington and Wyoming within the United States, and in British Columbia and Ontario within Canada. The Company also generates revenue through operation and maintenance (“O&M”) agreements with certain customers, through building and selling or leasing natural gas fueling stations to its customers, and through financing its customers’ vehicle purchases. In April 2008, the Company opened its first compressed natural gas (“CNG”) station in Lima, Peru through the Company’s joint venture, Clean Energy del Peru. In August 2008, the Company acquired 70% of the outstanding membership interests of Dallas Clean Energy, LLC (“DCE”). DCE, through a 70% owned subsidiary, owns a facility that collects, processes and sells renewable biomethane collected from a landfill in Dallas, Texas. On October 1, 2009, the Company acquired 100% of BAF Technologies, Inc. (“BAF”), a company that provides natural gas conversions, alternative fuel systems, application engineering, service and warranty support and research and development for natural gas vehicles. On September 7, 2010, the Company acquired 100% of IMW, a company engaged in the manufacturing and servicing of natural gas fueling compressors and related equipment. On December 15, 2010, the Company acquired 100% of Wyoming Northstar Incorporated, Southstar, LLC, and M&S Rental LLC (collectively “Northstar”), a provider of design, engineering, construction and maintenance services for liquefied natural gas (“LNG”) and liquefied to compressed (“LCNG”) fueling stations.

Basis of Presentation: The accompanying interim unaudited condensed consolidated financial statements include the accounts of the Company and its subsidiaries, and, in the opinion of management, reflect all adjustments, which include only normal recurring adjustments, necessary to state fairly the Company’s financial position, results of operations and cash flows for the three and six months ended June 30, 2010 and 2011. All intercompany accounts and transactions have been eliminated in consolidation. The three and six month periods ended June 30, 2010 and 2011 are not necessarily indicative of the results to be expected for the year ending December 31, 2011 or for any other interim period or for any future year.

Certain information and disclosures normally included in the notes to the financial statements have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”), but the resultant disclosures contained herein are in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) as they apply to interim reporting. The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements as of and for the year ended December 31, 2010 that are included in the Company’s Annual Report on Form 10-K filed with the SEC on March 10, 2011.

Use of Estimates: The preparation of consolidated financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and revenues and expenses during the reporting period. Actual results could differ from those estimates. Current economic conditions may require the use of additional estimates and these estimates may be subject to a greater degree of uncertainty as a result of the uncertain economy.

Note 2—Acquisitions

Natural Gas Fueling Compressors

On September 7, 2010, the Company, acting through certain of its subsidiaries, completed its purchase of the advanced natural gas fueling compressor and related equipment manufacturing and servicing business of IMW. IMW manufactures and services advanced, non-lubricated natural gas fueling compressors and related equipment for the global natural gas fueling market. IMW is headquartered near Vancouver, British Columbia, has a second manufacturing facility near Shanghai, China and has other sales and service offices in Bangladesh, Colombia, Peru and the United States.

Table of Contents

In connection with the closing of the Company’s acquisition of IMW, a subsidiary of the Company (the “Acquisition Subsidiary”) paid an upfront cash payment of approximately $15,034 and issued 4,017,408 shares of the Company’s common stock at closing to IMW’s shareholder. The issued shares were registered and available for immediate resale by the IMW shareholder. An additional $288 was paid by the Acquisition Subsidiary when the Chinese regulatory authorities subsequently approved the transfer of IMW Compressors (Shanghai) Co. Ltd. to the Acquisition Subsidiary. The Acquisition Subsidiary also issued the following promissory notes to the IMW shareholder (collectively, the “IMW Notes”): (i) a promissory note with a principal amount of $12,500 that was paid on January 31, 2011, (ii) a promissory note with a principal amount of $12,500 that is due and payable on January 31, 2012, (iii) a promissory note with a principal amount of $12,500 that is due and payable on January 31, 2013, and (iv) a promissory note with a principal amount of $12,500 that is due and payable on January 31, 2014. Each payment under the IMW Notes will consist of $5,000 in cash and $7,500 in cash and/or shares of the Company’s common stock (the exact combination of cash and/or stock to be determined at the Company’s option). In addition, pursuant to a security agreement executed at closing, the IMW Notes are secured by a subordinate security interest in IMW. On January 31, 2011, the Company paid $5,000 in cash and issued 601,926 shares to the IMW shareholder to settle the IMW Note due on that date.

IMW’s former shareholder may also receive additional contingent consideration based on future gross profits earned by IMW over the next four years. The additional contingent consideration is subject to achieving minimum gross profit targets and will be determined based on a sliding scale that increases at certain gross profit levels. During the four-year period during which these earn-out payments may be made, the former shareholder of IMW will receive between zero and 23% of the gross profit of IMW as additional consideration, up to a maximum of $40,000 in the aggregate (which maximum would be payable if IMW achieves approximately $174,000 in gross profit over the four-year period during which these earn-out payments may be made).

The Company accounted for this acquisition in accordance with FASB authoritative guidance for business combinations, which requires the Company to recognize the assets acquired and the liabilities assumed, measured at their fair values, as of the date of acquisition. The following table summarizes the allocation of the aggregate purchase price to the fair value of the assets acquired and liabilities assumed:

Current assets	$	27,149
Property, plant and equipment	2,559
Identifiable intangible assets	81,400
Goodwill	45,049
Total assets acquired	156,157
Liabilities assumed	(25,986		)
Total purchase price	$	130,171

Management allocated approximately $81,400 of the purchase price to certain identifiable intangible assets related to technology, customer relationships, non-compete agreements, and trademarks that were acquired with the acquisition. The fair value of the identifiable intangible assets will be amortized on a straight-line basis over their estimated useful lives ranging from three to twenty years. In addition, management allocated $45,049 to goodwill as part of the acquisition and recorded a contingent liability of $9,300 related to the additional contingent consideration described above. Under FASB authoritative guidance, the Company is required to adjust the value of the contingent consideration for this acquisition in the statement of operations as the value of the obligation changes each reporting period. The Company recorded a gain of $0 and $600, respectively, during the three and six month periods ended June 30, 2011. This amount is recorded in selling, general and administrative expenses in the accompanying condensed consolidated statement of operations. At June 30, 2011, the fair value of the contingent consideration was $7,500.

As of August 8, 2011, the purchase price allocation is preliminary and could change materially in subsequent periods. Any subsequent changes to the purchase price allocation that result in material changes to the Company’s consolidated financial results will be adjusted retroactively. The final purchase price allocation is pending the consideration of certain income tax related matters.

The results of operations of IMW have been included in the Company’s consolidated financial statements since September 7, 2010.

Liquefied Natural Gas Station Construction

On December 15, 2010, the Company acquired Northstar, a leading provider of design, engineering, construction and maintenance services for LNG and LCNG fueling stations. The purchase price primarily consisted of a closing cash payment in the amount of $7,414. The remaining consideration consists of five annual payments in the amount of $700 each commencing on the first anniversary of the closing date, and up to $4,000 in retention bonuses to certain key employees to be paid in four annual installments commencing on the first anniversary of the closing date.

Table of Contents

The Company accounted for this acquisition in accordance with FASB authoritative guidance for business combinations, which requires the Company to recognize the assets acquired and the liabilities assumed, measured at their fair values, as of the date of acquisition. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed as of December 15, 2010:

Current assets	$	4,434
Property, plant and equipment	941
Identifiable intangible assets	3,350
Goodwill	5,228
Total assets acquired	13,953
Liabilities assumed	(3,648		)
Total purchase price	$	10,305

Management allocated $3,350 of the purchase price to certain identifiable intangible assets, $2,250 of which is related to non-compete agreements, customer relationships, and backlog. The fair value of these identifiable intangibles is being amortized on a straight-line basis over their estimated useful lives ranging from one to ten years. The Company also allocated $1,100 of the purchase price to trademarks, which management believes has an indefinite useful life. In addition, management allocated $5,228 to goodwill as part of the acquisition.

The results of Northstar’s operations have been included in the Company’s consolidated financial statements since December 15, 2010.

Note 3—Cash and Cash Equivalents

The Company considers all highly liquid investments with maturities of three months or less on the date of acquisition to be cash equivalents.

Note 4—Derivative Transactions

The Company marks to market its open futures positions at the end of each period and records the net unrealized gain or loss during the period in derivative (gains) losses in the condensed consolidated statements of operations or in accumulated other comprehensive income in the condensed consolidated balance sheets in accordance with FASB authoritative guidance. The Company recorded unrealized (gains) losses of $3,862 and $(1,213), in other comprehensive income (loss) for the six month periods ended June 30, 2010 and 2011, respectively, related to its futures contracts. Of the $2,858 liability for the Company’s future contracts at June 30, 2011, $2,715 is included in accrued liabilities for the short-term amount, and $143 is included in other long-term liabilities for the long-term amount in the Company’s consolidated balance sheet as of June 30, 2011. Of the $3,703 liability for the Company’s futures contracts at June 30, 2010, $2,168 is included in accrued liabilities for the short-term amount, and $1,535 is included in other long-term liabilities for the long-term amount in the Company’s condensed consolidated balance sheet as of June 30, 2010. The Company’s ineffectiveness related to its futures contracts during the three and six month periods ended June 30, 2010 and 2011 was insignificant. For the three months ended June 30, 2010 and 2011, the Company recognized a loss of approximately $350 and $680, respectively, in cost of sales in the accompanying condensed consolidated statements of operations related to its futures contracts that were settled during the respective periods. For the six months ended June 30, 2010 and 2011, the Company recognized a loss of $137 and $1,431, respectively, in cost of sales in the accompanying condensed consolidated statements of operations related to its futures contracts that were settled during the respective periods.

The following table presents the notional amounts and weighted-average fixed prices per gasoline gallon equivalent of the Company’s natural gas futures contracts as of June 30, 2011:

	Gallons	Weighted Average Price Per Gasoline Gallon Equivalent
July to December, 2011	5,920,000	$	0.82
2012	5,160,000	$	0.81
January to May, 2013	300,000	$	0.81

Table of Contents

Note 5—Other Receivables

Other receivables at December 31, 2010 and June 30, 2011 consisted of the following:

	December 31, 2010		June 30, 2011
Loans to customers to finance vehicle purchases	$	1,013	$	1,236
Capital lease receivables	273		353
Accrued customer billings	1,976		6,814
Fuel tax and carbon credits	17,577		4,629
Other	6,441		4,365
	$	27,280	$	17,397

Note 6—Inventories

Inventories are stated at the lower of cost or market on a first-in, first-out basis. Management’s estimate of market includes a provision for slow-moving or obsolete inventory based upon inventory on hand and forecasted demand.

Inventories consisted of the following as of December 31, 2010 and June 30, 2011:

	December 31, 2010		June 30, 2011
Raw materials and spare parts	$	17,634	$	24,452
Work in process	1,196		2,974
Finished goods	1,653		2,009
Total	$	20,483	$	29,435

Note 7—Land, Property and Equipment

Land, property and equipment at December 31, 2010 and June 30, 2011 are summarized as follows:

	December 31, 2010			June 30, 2011
Land	$	1,198		$	1,198
LNG liquefaction plants	92,856			92,924
Biomethane plants	2,867			14,598
Station equipment	91,492			108,220
LNG trailers	12,020			12,368
Other equipment	21,611			21,481
Construction in progress	53,386			51,004
	275,430			301,793
Less: accumulated depreciation	(63,787		)	(72,719		)
	$	211,643		$	229,074

Note 8—Investments in Other Entities

Through June 30, 2011, the Company has invested approximately $12,288 in The Vehicle Production Group LLC (“VPG”), a company that is developing a natural gas vehicle made in the United States for taxi and paratransit use. The Company accounts for its investment in VPG under the cost method of accounting as the Company does not have the ability to exercise significant influence over VPG’s operations.

On February 25, 2011 (the “Closing Date”), the Company paid $1,200 for a 19.9% interest in ServoTech Engineering, Inc. (“ServoTech”), a company that provides design and engineering services for natural gas fueling systems among other services. The Company also has an option to purchase the remaining 81.1% of ServoTech for $2,800 over the 15 month period following the Closing Date. The Company accounts for its interest using the equity method of accounting as the Company has the ability to exercise significant influence over ServoTech’s operations.

Table of Contents

Note 9—Accrued Liabilities

Accrued liabilities at December 31, 2010 and June 30, 2011 consisted of the following:

	December 31, 2010		June 30, 2011
Salaries and wages	$	2,218	$	3,767
Accrued employee benefits	1,659		2,519
Accrued gas and equipment purchases	6,995		10,057
Derivative liability	3,060		2,715
Contingent consideration obligations	3,493		1,141
Accrued property and other taxes	3,999		2,364
Accrued warranty liability	2,338		2,729
Other	4,375		4,127
	$	28,137	$	29,419

Note 10—Warranty Liability

The Company records warranty liabilities at the time of sale for the estimated costs that may be incurred under its standard warranty. Changes in the warranty liability are presented in the following tables:

	June 30, 2010			June 30, 2011
Warranty liability at beginning of year	$	1,136		$	2,338
Assumed liability through acquisitions	—			—
Costs accrued for new warranty contracts and changes in estimates for pre-existing warranties	202			723
Service obligations honored	(106		)	(332		)
Warranty liability at end of period	$	1,232		$	2,729

Note 11—Long-term Debt

In conjunction with the Company’s acquisition of its 70% interest in Dallas Clean Energy, LLC (“DCE”), on August 15, 2008, the Company entered into a credit agreement (“Credit Agreement”) with PlainsCapital Bank (“PCB”). The Company borrowed $18,000 (the “Facility A Loan”) to finance the acquisition of its membership interests in DCE. The Company also obtained a $12,000 line of credit from PCB to finance capital improvements of the DCE processing facility and to pay certain costs and expenses related to the acquisition and the PCB loans (the “Facility B Loan”).

On October 7, 2009, the Facility A Loan was repaid in full and converted into a $20,000 line of credit (the “A Line of Credit”) pursuant to an amendment to the Credit Agreement. On August 13, 2010, the Credit Agreement was amended to extend the maturity date of the A Line of Credit to August 14, 2011 and add an unused facility fee. The amendment also provides for a 1-year option to extend the maturity date to August 14, 2012, subject to the Company not being in default on the A Line of Credit. The unused facility fees are to be paid quarterly, in an amount equal to one-tenth of one percent (0.10%) of the unused portion. As of June 30, 2011, the Company did not have any amounts outstanding under the A Line of Credit.

The principal amount of the Facility B Loan became due and payable in annual payments commencing on August 1, 2009, and continuing each anniversary date thereafter, with each such payment being in an amount equal to the lesser of twenty percent of the aggregate principal amount of the Facility B Loan then outstanding or $2,800. Pursuant to an amendment to the Facility B loan between the Company and PCB dated November 1, 2010, PCB agreed to forgo the scheduled payment due from the Company on August 1, 2010 in the amount of $2,059 until January 31, 2011, which payment was made on such date. On March 31, 2011, the Company paid in full the remaining principal and interest that was due under the Facility B Loan.

Interest accrues daily on the amounts outstanding under the Credit Agreement at the greater of the prime rate of interest for the United States plus 0.50% per annum, or 5.50% per annum. The Company paid a facility fee of $300 in August 2008 in connection with the Credit Agreement. As of June 30, 2011, the unamortized balance of the facility fee was $77. Amortization of the facility fee is recorded as additional interest expense in the condensed consolidated statements of operations.

Table of Contents

The Credit Agreement requires the Company to comply with certain covenants. The Company may not incur indebtedness or liens except as permitted by the Credit Agreement, or declare or pay dividends. The Company must maintain, on a quarterly basis, minimum liquidity of not less than $6,000, accounts receivable balances, as defined, of not less than $8,000, consolidated net worth, as defined, of not less than $150,000, and a debt to equity ratio, as defined, of not more than 0.3 to 1.0. Beginning in the quarter ended June 30, 2009, the Company must also maintain a minimum debt service ratio, as defined, of 1.5 to 1.0 at each quarter end. In computing these amounts, the Company excludes the financial results and amounts of IMW. Effective in the fourth quarter of 2008, the Company established a lock-box arrangement with PCB subject to the Credit Agreement. Funds from the Company’s customers, excluding Shell Energy North America (US) after March 25, 2011, are remitted to the lock-box and then deposited to a PCB bank account. The remitted funds are not used to pay-down the balance of the Credit Agreement. However, if the Company defaults on the Credit Agreement, all of the obligations under the Credit Agreement will become immediately due and payable and all funds received in the Company’s lock-box held by PCB will be applied to the balance due on the A Line of Credit. One of the events of default is the occurrence of a “material adverse change,” which is a subjective acceleration clause. Based on the authoritative guidance for balance sheet classification of borrowings outstanding under revolving credit agreements that include both a subjective acceleration clause and a lock-box arrangement, the Company has classified its debt pursuant to the Credit Agreement as short-term or long-term, as appropriate, and believes that the likelihood of an event of default is more than remote, but not more likely than not.

One of the Company’s bank covenants is a requirement to maintain accounts receivable balances from certain subsidiaries above $8,000 at each quarter end during the term. Because the Company’s revenues are dependent on the price of natural gas and the volume of natural gas the Company delivers, to the extent natural gas prices fall or the Company’s volumes decline, the Company could violate this covenant in the future. Beginning with the quarter ended June 30, 2009, the Company has been required to maintain a debt service ratio, as defined, of not less than 1.5 to 1.0. To the extent the Company’s operating results do not materialize as planned, the Company could violate this covenant in the future. As of June 30, 2011, the Company was in compliance with its covenants. The Credit Agreement is secured by the Company’s interest in DCE, certain of the Company’s accounts receivable and inventory balances and 45 of the Company’s LNG tanker trailers. The net book value of the collateral securing the PCB loans was approximately $49,483 at June 30, 2011. The Company maintains $2,500 in a payment reserve account at PCB. PCB may, in the event of a default, withdraw funds from the account to apply to the principal and interest payments due on the A Line of Credit. Such amount is included as restricted cash in the Company’s condensed consolidated balance sheet at June 30, 2011.

In conjunction with the DCE acquisition mentioned above, the Company also entered into a Loan Agreement with DCE (the “DCE Loan”) to provide secured financing of up to $14,000 to DCE for future capital expenditures or other uses as agreed to by the Company, in its sole discretion. On March 31, 2011, the entire amount of unpaid principal and interest due under the DCE Loan was paid to the Company. The interest income related to the DCE Loan was eliminated in the accompanying condensed consolidated statements of operations.

On March 25, 2011, the Company’s 70% owned subsidiary, Dallas Clean Energy McCommas Bluff, LLC, a Delaware limited liability company (“DCEMB”), arranged for a $40,200 tax-exempt bond issuance (the “Revenue Bonds”). The Revenue Bonds will be repaid from the revenue generated by DCEMB from the sale of renewable natural gas (or biomethane). The Revenue Bonds are secured by the revenue and assets of DCEMB and are non-recourse to DCEMB’s direct and indirect parent companies, including the Company. The bond repayments are amortized through December 2024 and the average coupon interest rate on the bonds is 6.60%. The bond issuance closed March 31, 2011.

The bond proceeds will primarily be used to finance further improvements and expansion of the landfill gas processing facility owned by DCEMB at the McCommas Bluff landfill outside of Dallas, Texas. A portion of the proceeds were used to retire the DCE Loan discussed above. The Company, in turn, used the proceeds from the payoff of the DCE Loan to repay approximately $8,000 owed by the Company to PCB under the Facility B Loan on March 31, 2011.

Pursuant to the Loan Agreement, dated as of January 1, 2011 (the “Loan Agreement”), between DCEMB and the Mission Economic Development Corporation (the “Issuer”), DCEMB has covenanted with the Issuer to make loan repayments equal to the principal and interest coming due on the Revenue Bonds. DCEMB executed a promissory note, dated March 31, 2011 (the “Note”), as evidence of its obligations under the Loan Agreement. Pursuant to the Trust Indenture, dated as of January 1, 2011 (the “Indenture”), the Issuer has pledged and assigned to the Trustee all of the Issuer’s right, title and interest in and to the Loan Agreement (with certain specified exceptions) and the Note.

The obligations of DCEMB under the Loan Agreement are secured by a Leasehold Deed of Trust, Assignment of Rents, Security Agreement and Fixture Filing, dated as of January 1, 2011 (the “Deed of Trust”), executed by DCEMB in favor of the deed of trust trustee named therein for the benefit of the Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”). In addition, DCEMB executed a Security Agreement (the “Security Agreement”), as security for its obligations, pursuant to which DCEMB granted to the Trustee a security interest in all right, title and interest of DCEMB to the Collateral (as defined in the Security Agreement), which includes, but is not limited to, DCEMB’s rights, title and interest in any gas sale agreements, including the gas sale agreement with Shell Energy North America (US), L.P. (the “Shell Gas Sale Agreement”), and the funds and accounts held under the Indenture.

Table of Contents

Pursuant to a Consent and Agreement, by and between Shell Energy, The Bank of New York Mellon Trust Company, N.A., as Depository Bank (the “Depository Bank”), DCEMB and the Trustee, dated as of January 1, 2011 (the “Consent Agreement”), Shell Energy agreed to make all payments due to DCEMB under the Shell Gas Sale Agreement to the Depository Bank. In addition, other revenues generated through the sale of gas produced at the facility will be paid directly to the Depository Bank pursuant to a Depository and Control Agreement, dated as of January 1, 2011 (the “Depository Agreement”), among DCEMB, the Trustee and the Depository Bank.

All payments received by the Depository Bank will be placed into various accounts in accordance with the requirements of the Indenture and the Depository Agreement. The funds in these accounts will be used to service required debt payments, finance further improvements and expansion of the landfill gas processing facility owned by DCEMB, finance the operations and maintenance of DCEMB, finance certain expenses associated with setting up and maintaining the accounts, and other uses as prescribed in the Depository Agreement. The Depository Bank will make payments out of these accounts in accordance with the requirements of the Depository Agreement. At the end of each month after all required account fundings have been fulfilled in accordance with the Depository Agreement, all remaining excess funds will be placed into a Surplus Account. The funds in the Surplus Account will be delivered to DCEMB so long as (i) DCEMB’s Debt Service Coverage Ratio (as defined) for the most recent four calendar quarters then ended equals or exceeds 1.25:1, (ii) DCEMB’s Debt Service Coverage Ratio (as defined) is reasonably projected to equal or exceed 1.25:1 for the next four calendar quarters, (iii) no events of default have occurred as defined by the Indenture and the Loan Agreement, and (iv) after giving effect to the transfer, DCEMB’s Minimum Days Cash on Hand (as defined) shall be, or shall at any time be projected to be, more than the lesser of thirty-five Days Cash on Hand (as defined) or $1,300. Due to these restrictions on this cash, the Company has classified all of this cash as restricted cash on the balance sheet. The Company records the restricted cash that is expected to be received and used within the next 12 months from the Depository Bank for working capital and operating purposes as current in its balance sheet, and presents the remaining balance as non-current in the line item notes receivable and other long term assets. At June 30, 2011, $23,044 was included in long term assets and $3,200 was included in restricted cash in the accompanying condensed consolidated balance sheet.

The Indenture and the Loan Agreement have certain non-financial debt covenants with which DCEMB must comply. As of June 30, 2011, DCEMB was in compliance with all its debt covenants.

Pursuant to a collateral assignment and Consent and Agreement with Atmos Pipeline - Texas (“Atmos”), DCEMB has collaterally assigned to the Trustee, subject to certain reserved rights and the consent of Atmos, the transportation agreements of the Company with Atmos.

In connection with the closing of the Company’s acquisition of IMW, the Company issued the IMW Notes (see note 2).

Also in connection with the closing of the Company’s acquisition of IMW, the Company entered into an Assumption Agreement (the “Assumption Agreement”) with HSBC Bank Canada (“HSBC”), which was amended on March 29, 2011, pursuant to which the Company assumed the obligations and liabilities of IMW under the following arrangements, as amended, with HSBC (collectively, the “IMW Lines of Credit”):

(i)	An operating line of credit with a limit of $10,000 in Canadian dollars (“CAD”) bearing interest at prime plus 1.25%, to assist in financing the day-to-day working capital needs of IMW.

(ii)	A bank guarantee line with a limit of CAD$3,000, which allows IMW to provide guarantees and/or standby letters of credit to overseas suppliers or bid/performance deposits on contracts.

(iii)	A forward exchange contract line with a limit of CAD$13,750. The forward exchange contract line allows IMW to enter into foreign exchange forward contracts up to the notional limit of CAD$13,750 (no forward exchange contracts were outstanding at June 30, 2011).

(iv)	A MasterCard limit with a maximum amount of CAD$150.

(v)	An operating line with a limit of 5,000 Renminbi (“RMB”) (CAD$746) bearing interest at the 6 month People’s Bank of China rate plus 2.5% and a sub-limit bank guarantee line of 5,000 RMB. The aggregate of the balances in the lines cannot exceed 5,000 RMB.

(vi)	A 16,750 Bengali Taka (CAD$221) operating line of credit bearing interest at 14%.

(vii)	A 170,000 Columbian Peso (CAD$92) operating line of credit bearing interest at the Colombia benchmark rate plus 7 to 9%.

Table of Contents

The IMW Lines of Credit are secured by a general security agreement providing a first priority security interest in all present and after acquired personal property of IMW, including specific charges on all serial numbered goods, inventory and other assets and assignment of risk insurance (the “Security”). The IMW Lines of Credit contain no fixed repayment terms or mandatory principal payments and are due on demand. Based on the relevant accounting guidance, the Company has classified this debt pursuant to the credit agreement as short-term given that it is due on demand.

The Assumption Agreement with HSBC also includes certain financial covenants. Among these financial covenants are that IMW shall not permit: 1) its ratio of debt to tangible net worth to be greater than 3.25 to 1.0 until December 31, 2010, and greater than 4.0 to 1.0 from January 1, 2011 through June 30, 2011, and greater than 3.0 to 1.0 on or after July 1, 2011, 2) its tangible net worth to at anytime be below CAD$3,000 and 3) its ratio of current assets to current liabilities to be less than 1.15 to 1.0 until December 31, 2010 and less than 1.25 to 1.0 on or after January 1, 2011. IMW was in compliance with the financial covenants as of June 30, 2011.

In addition, the Company and IMW agreed that should the making of any scheduled payment by IMW to the seller of IMW under the IMW Notes result in IMW being in breach of the Assumption Agreement, the IMW Lines of Credit or the Security, the Company shall furnish IMW with the funds needed to remain in compliance with the Assumption Agreement, the IMW Lines of Credit and the Security. Further, the Company and IMW agreed that should IMW make any future earn-out payments to the seller of IMW in connection with the acquisition of IMW, and should the making of such earn-out payments result in IMW being in breach of the Assumption Agreement, the IMW Lines of Credit or the Security, then the Company shall furnish IMW with the funds needed to make such earn-out payments and remain in compliance with the Assumption Agreement, the IMW Lines of Credit and the Security.

In connection with the closing of the Company’s acquisition of Northstar, the Company agreed to make future payments consisting of five annual payments in the amount of $700 each with the first payment due December 15, 2011. The carrying amount of these future payment obligations at June 30, 2011 was $2,993. The difference between the carrying amount and the face amount will be accreted to interest expense over the remaining term of the obligations.

Long-term debt at December 31, 2010 and June 30, 2011 consisted of the following:

	December 31, 2010			June 30, 2011
Facility B loan	$	9,909		$	—
IMW future payment notes	44,568			33,539
Northstar future payments	2,900			2,993
DCE notes	435			585
DCEMB notes (non recourse to the Company)	—			40,200
IMW assumed debt	4,626			9,588
Capital lease obligations	1,978			3,087
Total debt and capital lease obligations	64,416			89,992
Less amounts due within one year and short-term borrowings	(22,712		)	(23,941		)
Total long-term debt and capital lease obligations	$	41,704		$	66,051

Note 12—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 June 30,		Six Months Ended June 30,
	2010	2011	2010	2011
Basic:
Weighted average number of common shares outstanding	60,876,741	70,302,782	60,494,148	70,199,963
Diluted:
Shares issued upon assumed exercise of stock options	2,781,015	—	—	—
Shares issued upon assumed exercise of warrants	8,202,119	—	—	—
Shares used in computing diluted earnings per share	71,859,875	70,302,782	60,494,148	70,199,963

Certain securities were excluded from the diluted earnings per share calculations for the six-months ended June 30, 2010 and 2011, respectively, as the inclusion of the securities would be anti-dilutive to the calculation. The amounts outstanding as of June 30, 2010 and 2011 for these instruments are as follows:

	June 30,
	2010	2011
Options	9,251,858	10,802,155
Warrants	18,314,394	17,130,682

Table of Contents

Note 13—Comprehensive Loss

The following table presents the Company’s comprehensive loss for the six months ended June 30, 2010 and 2011:

	Six Months Ended June 30,
	2010			2011
Net loss attributable to Clean Energy Fuels Corp.	$	(14,472	)	$	(15,372	)
Derivative unrealized gains (losses)	(3,862		)	1,213
Foreign currency translation adjustments	(32		)	(697		)
Comprehensive loss	$	(18,366	)	$	(14,856	)

Note 14—Stock-Based Compensation

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

	Three Months Ended June 30,			Six Months Ended June 30,
	2010		2011	2010		2011
Stock options:
Stock-based compensation expense	$	2,922	3,555	$	5,962	6,932
Income tax benefit	—		—	—		—
Stock-based compensation expense, net of tax	$	2,922	3,555	$	5,962	6,932

Stock Options

The following table summarizes the Company’s stock option activity during the six months ended June 30, 2011:

	Number of Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value
Outstanding, December 31, 2010	10,433,551		$	10.09
Options granted	778,500		13.99
Options exercised	(105,723	)	6.94
Options forfeited	(304,173	)	15.59
Outstanding, June 30, 2011	10,802,155		$	10.25	6.72	$	31,367
Exercisable, June 30, 2011	7,049,974		$	9.08	5.61	$	28,666

As of June 30, 2011, there was $24,143 of total unrecognized compensation cost related to unvested shares. That cost is expected to be recognized over a weighted-average period of 1.47 years. The total fair value of shares vested during the six months ended June 30, 2011 was $2,194.

All of the Company’s unvested options issued prior to October 2005 vested in October 2005 when the Company experienced a change in control in accordance with the 2002 Plan. The Company plans to issue new shares to its employees upon the employees’ exercise of their options. The intrinsic value of all options exercised during the six months ended June 30, 2010 and 2011 was $4,975 and $657, respectively.

The fair value of each option is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions used for grants in 2011:

		Six Months Ended June 30, 2011
Dividend yield		0.00%
Expected volatility		69.94% to 72.43%
Risk-free interest rate		1.95% to 2.71%
Expected life in years		6.0

Table of Contents

The weighted-average grant date fair values of options granted during the six months ended June 30, 2010 and 2011 were $11.91, and $9.07, respectively. The volatility amounts used during the period were estimated based on a certain peer group of the Company’s historical volatility for a period commensurate with the expected life of the options granted, the Company’s historical volatility, and the Company’s implied future volatility. The expected lives used during the periods were based on the weighted-average of the historical exercise behavior of prior options granted and the estimated future exercise date of the options outstanding. The risk free rates used during the year were based on the U.S. Treasury yield curve at the time of grant. The Company recorded $5,962 and $6,932 of stock option expense during the six months ended June 30, 2010 and 2011, respectively. The Company has not recorded any tax benefit related to its stock option expense.

Note 15—Environmental Matters, Litigation, Claims, Commitments and Contingencies

The Company is subject to federal, state, local, and foreign environmental laws and regulations. The Company does not anticipate any expenditures to comply with such laws and regulations that 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 may become 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.

Note 16—Income Taxes

The Company is required to recognize the impact of a tax position in its financial statements if the position is more likely than not of being sustained by the taxing authority upon examination, based on the technical merits of the position. The Company accrues interest based on the difference between a tax position recognized in the financial statements and the amount claimed on its returns at statutory interest rates. The net interest incurred was immaterial for the three and six month periods ended June 30, 2010 and 2011. Further, the Company accrues penalties if the tax position does not meet the minimum statutory threshold to avoid penalties. No penalties have been accrued by the Company. The Company’s unrecognized tax benefits as of June 30, 2011 are unchanged from December 31, 2010.

The Company is subject to taxation in the United States and various states and foreign jurisdictions. The Company’s tax years for 2006 through 2010 are subject to examination by various tax authorities. The Company is no longer subject to U.S. examination for years before 2007 or state examinations for years before 2006. On July 15, 2010, the Internal Revenue Service (“IRS”) sent the Company a letter disallowing approximately $5,073 related to certain claims the Company made from October 1, 2006 to June 30, 2008 under the Volumetric Excise Tax Credit program. The Company believes its claims were properly made and has appealed the IRS’s request for payment.

The Company’s tax benefit for the period ended June 30, 2010 includes a refund of approximately $1,300 of alternative minimum taxes previously paid attributable to the Company’s election of the extended net operating loss five-year carryback provision under the Worker, Homeownership, and Business Assistance Act of 2009.

Note 17—Fair Value Measurements

The Company follows the FASB authoritative guidance for fair value measurements with respect to assets and liabilities that are measured at fair value on a recurring basis and nonrecurring basis. Under the standard, fair value is defined as the exit price, or the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The standard also establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs market participants would use in valuing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions about the factors

Table of Contents

market participants would use in valuing the asset or liability developed based upon the best information available in the circumstances. The hierarchy is broken down into three levels. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and inputs (other than quoted prices) that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. Categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement.

During the six months ended June 30, 2011, the Company’s financial instruments consisted of natural gas futures contracts, debt instruments, contingent consideration related to its acquisitions, and its Series I warrants. The fair market value of the Company’s debt instruments approximated their carrying values at June 30, 2010 and 2011. The Company uses quoted forward price curves, discounted to reflect the time value of money, to value its natural gas futures contracts. The Company uses projected financial results for the respective entities, discounted to reflect the time value of money, to value its contingent consideration obligations. The Company uses either a Monte Carlo simulation model or the Black-Scholes model, depending on the current terms, to value the Series I warrants. The Company considers a variety of market data with observable inputs when estimating the expected volatility used in the model. For example, the Company considers the historical volatilities of its competitors, the call option value of convertible bonds of certain peer group entities and the implied volatilities of its exchange traded stock options. The Company also uses the implied volatilities of its short-term (i.e. 3 to 9 month) traded options and extrapolates the data over the remaining term of the Series I warrants, which was approximately 4.83 years as of June 30, 2011. Given that the extrapolation beyond the term of the short term exchange traded options is not based on observable market inputs for a significant portion of the remaining term of the warrants, the Series I warrants have been classified as a Level 3 fair value determination in the table below.

The following tables provide information by level for assets and liabilities that are measured at fair value on a recurring basis:

Description	Balance at June 30, 2011		Quoted Prices In Active Markets for Identical Items (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Liabilities:
Natural gas futures contracts	$	2,858	$	—	$	2,858	$	—
Contingent consideration obligations	8,341		—		—		8,341
Series I warrants	12,613		—		—		12,613

The following tables provide a reconciliation of the beginning and ending balances of items measured at fair value on a recurring basis in the table above that used significant unobservable inputs (Level 3).

Liabilities: Contingent Consideration	June 30, 2010		June 30, 2011
Beginning Balance	$	3,100	$	11,200
Business combinations	—		—
Total (gain) loss included in earnings	500		(700		)
Payments	—		(2,159		)
Transfers In/Out	—		—
Ending Balance	$	3,600	$	8,341

Liabilities: Series I Warrants	June 30, 2010		June 30, 2011
Beginning Balance	$	29,741	$	14,148
Total (gain) loss included in earnings	1,989		(1,535		)
Issuance of warrants	—		—
Exercise of warrants	—		—
Transfers In/Out	—		—
Ending Balance	$	31,730	$	12,613

Note 18—Recently Adopted Accounting Changes and Recently Issued Accounting Standards

On January 1, 2011, the Company adopted changes issued by the FASB to disclosure requirements for fair value measurements. Specifically, the changes require a reporting entity to disclose, in the reconciliation of fair value measurements using significant unobservable inputs (Level 3), separate information about purchases, sales, issuances, and settlements (that is, on a gross basis rather than as one net number). In addition, the changes require a reporting entity to separately disclose the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers. These changes were applied to the disclosures in note 17 to the Company’s condensed consolidated financial statements contained elsewhere herein.

Table of Contents

On January 1, 2011, the Company adopted changes issued by the FASB to the testing of goodwill for impairment. These changes require an entity to perform all steps in the test for a reporting unit whose carrying value is zero or negative if it is more likely than not (more than 50%) that a goodwill impairment exists based on qualitative factors. This will result in the elimination of an entity’s ability to assert that such a reporting unit’s goodwill is not impaired and additional testing is not necessary despite the existence of qualitative factors that indicate otherwise. The adoption of this pronouncement did not have any impact on the Company’s condensed consolidated financial statements.

On January 1, 2011, the Company adopted changes issued by the FASB to the disclosure of pro forma information for business combinations. These changes clarify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. Also, the existing requirements for supplemental pro forma disclosures were expanded to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The adoption of this pronouncement did not have any impact on the Company’s condensed consolidated financial statements.

In May 2011, the FASB issued changes to conform existing guidance regarding fair value measurement and disclosure between GAAP and International Financial Reporting Standards. These changes both clarify the FASB’s intent about the application of existing fair value measurement and disclosure requirements and amend certain principles or requirements for measuring fair value or for disclosing information about fair value measurements. The clarifying changes relate to the application of the highest and best use and valuation premise concepts, measuring the fair value of an instrument classified in a reporting entity’s shareholders’ equity, and disclosure of quantitative information about unobservable inputs used for Level 3 fair value measurements. The amendments relate to measuring the fair value of financial instruments that are managed within a portfolio; application of premiums and discounts in a fair value measurement; and additional disclosures concerning the valuation processes used and sensitivity of the fair value measurement to changes in unobservable inputs for those items categorized as Level 3, a reporting entity’s use of a nonfinancial asset in a way that differs from the asset’s highest and best use, and the categorization by level in the fair value hierarchy for items required to be measured at fair value for disclosure purposes only. These changes become effective for the Company on January 1, 2012. The Company is currently evaluating the potential impact of these changes on its consolidated financial statements.

In June 2011, the FASB issued changes to the presentation of comprehensive income. These changes give an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The option to present components of other comprehensive income as part of the statement of changes in stockholders’ equity was eliminated. The items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income were not changed. Additionally, no changes were made to the calculation and presentation of earnings per share. These changes become effective for the Company on January 1, 2012. The Company is currently evaluating these changes to determine which option will be chosen for the presentation of comprehensive income. Other than the change in presentation, the Company has determined these changes will not have an impact on its consolidated financial statements.

Note 19—Volumetric Excise Tax Credit (“VETC”)

The Company records its VETC credits as revenue in its condensed consolidated statements of operations as the credits are fully refundable and do not need to offset income tax liabilities to be received. VETC revenues for the six month periods ended June 30, 2010 and 2011 were $0 and $8,902, respectively. The legislation providing for VETC was reinstated in the fourth quarter of 2010, made retroactive to January 1, 2010 and extended to December 31, 2011. During the fourth quarter of 2010, the Company recorded $16,042 of VETC revenue, which included $7,534 related to the six month periods ended June 30, 2010.

Note 20—Subsequent Events

On July 11, 2011, the Company entered into a Loan Agreement (the “Loan Agreement”) with Chesapeake NG Ventures Corporation (“Chesapeake”), an indirect wholly owned subsidiary of Chesapeake Energy Corporation, whereby Chesapeake agreed to purchase from the Company up to $150 million aggregate principal amount of debt securities for the development, construction and operation of liquefied natural gas stations (the “Note Financing”) pursuant to the issuance of three convertible promissory notes, each having a principal amount of $50 million (each a “Note” and collectively the “Notes”). Chesapeake Energy Corporation guaranteed Chesapeake’s commitment to purchase the Notes under the Loan Agreement.

Table of Contents

The first Note was issued on July 11, 2011, and the Company expects to issue the second and third Notes on June 29, 2012 and June 28, 2013, respectively. The Notes bear interest at the rate of 7.5% per annum (payable quarterly, in arrears, on March 31, June 30, September 30 and December 31 of each year, beginning on September 30, 2011) and are convertible at Chesapeake’s option into shares of the Company’s common stock (the “Shares”) at $15.80 per share. Subject to certain restrictions, the Company can force conversion of each Note into Shares if, following the second anniversary of the issuance of a Note, the Shares trade at a 40% premium to the Conversion Price for at least twenty trading days in any consecutive thirty trading day period. The entire principal balance of each Note is due and payable seven years following its issuance, and the Company may repay each Note in Shares or cash. The Loan Agreement restricts the use of the Note Financing proceeds to financing the development, construction and operation of LNG stations and payment of certain related expenses. The Loan Agreement also provides for customary events of default which, if any of them occurs, would permit or require the principal of and accrued interest on the Notes to become or to be declared due and payable.

On July 14, 2011, the Company invested an additional $717 in VPG.

On July 5, 2011, the Company invested an additional $607 in Clean Energy del Peru.

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

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (this “MD&A”) should be read together with the unaudited condensed consolidated financial statements and the related notes included elsewhere in this report. For additional context with which to understand our financial condition and results of operations, refer to the MD&A for the fiscal year ended December 31, 2010 contained in our 2010 Annual Report on Form 10-K filed with the SEC on March 10, 2011, as well as the consolidated financial statements and notes contained therein.

Cautionary Statement Regarding Forward Looking Statements

This MD&A and other sections of this report contain forward looking statements. We make forward-looking statements, as defined by the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, and in some cases, you can identify these statements by forward-looking words such as “if,” “shall,” “may,” “might,” “will likely result,” “should,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “project,” “intend,” “goal,” “objective,” “predict,” “potential” or “continue,” or the negative of these terms and other comparable terminology. These forward-looking statements, which are based on various underlying assumptions and expectations and are subject to risks, uncertainties and other unknown factors, may include projections of our future financial performance based on our growth strategies and anticipated trends in our business. These statements are only predictions based on our current expectations and projections about future events that we believe to be reasonable. There are important factors that could cause our actual results, level of activity, performance or achievements to differ materially from the historical or future results, level of activity, performance or achievements expressed or implied by such forward-looking statements. These factors include, but are not limited to, those discussed under the caption “Risk Factors” in this report and in our 2010 Annual Report on Form 10-K. In preparing this MD&A, we presume that readers have access to and have read the MD&A in our 2010 Annual Report on Form 10-K pursuant to Instruction 2 to paragraph (b) of Item 303 of Regulation S-K. We undertake no duty to update any of these forward-looking statements after the date of filing of this report to conform such forward-looking statements to actual results or revised expectations, except as otherwise required by law.

We provide natural gas solutions for vehicle fleets primarily in the United States. Our primary business activity is selling compressed natural gas (“CNG”) and liquefied natural gas (“LNG”) vehicle fuel to our customers. We also build, operate and maintain fueling stations, manufacture and service advanced natural gas fueling compressors and related equipment, process and sell renewable biomethane and provide natural gas vehicle conversions. Our customers include fleet operators in a variety of markets, such as public transit, refuse hauling, airports, taxis and regional trucking. In April 2008, we opened our first CNG station in Lima, Peru, through our joint venture, Clean Energy del Peru. In August 2008, we acquired 70% of the outstanding membership interests of DCE. DCE owns a facility that collects, processes and sells renewable biomethane at the McCommas Bluff landfill in Dallas, Texas. On October 1, 2009, we acquired 100% of BAF Technologies, Inc. (“BAF”), a company that provides natural gas conversions, alternative fuel systems, application engineering, service and warranty support and research and development for natural gas vehicles. On September 7, 2010, we completed the purchase of IMW, a company that manufactures and services advanced, non-lubricated natural gas fueling compressors and related equipment. On December 15, 2010, we acquired Northstar, which provides design, engineering, construction and maintenance services for LNG and liquefied to compressed natural gas (“LCNG”) fueling stations.

Overview

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

Table of Contents

Sources of revenue. We generate a significant portion of our revenue from selling CNG and LNG and providing operations and maintenance services to our customers. The balance of our revenue is provided by designing and constructing natural gas fueling stations, financing our customers’ natural gas vehicle purchases, sales of pipeline quality biomethane produced by DCE, sales of natural gas vehicle conversions through our wholly owned subsidiary BAF, and commencing on September 7, 2010, sales of advanced natural gas fueling compressors and related equipment and maintenance services through IMW. In addition, on December 15, 2010, we began generating revenue from LNG and LCNG fueling station design, engineering, construction and maintenance services through Northstar.

Key operating data. In evaluating our operating performance, our management focuses primarily on: (1) the amount of CNG and LNG gasoline gallon equivalents delivered (which we define as (i) the volume of gasoline gallon equivalents we sell to our customers, plus (ii) the volume of gasoline gallon equivalents dispensed to our customers at stations where we provide operating and maintenance (“O&M”) services, but do not directly sell the CNG or LNG, plus (iii) our proportionate share of the gasoline gallon equivalents sold as CNG by our joint venture in Peru, plus (iv) our proportionate share of the gasoline gallon equivalents of biomethane produced and sold as pipeline quality natural gas by DCE), (2) our gross margin (which we define as revenue minus cost of sales), and (3) net income (loss). The following table, which you should read in conjunction with our condensed consolidated financial statements and notes contained elsewhere in this quarterly report on Form 10-Q and our consolidated financial statements and notes contained in our annual report on Form 10-K for the year ended December 31, 2010, presents our key operating data for the years ended December 31, 2008, 2009, and 2010 and for the three and six months ended June 30, 2010 and 2011:

Gasoline gallon equivalents delivered (in millions)	Year Ended December 31, 2008			Year Ended December 31, 2009			Year Ended December 31, 2010			Three Months Ended June 30, 2010			Three Months Ended June 30, 2011			Six Months Ended June 30, 2010			Six Months Ended June 30, 2011
CNG	47.6			67.9			81.4			20.6			25.6			39.8			48.3
Biomethane	2.0			6.4			7.4			1.9			1.7			3.8			3.2
LNG	23.9			26.7			33.9			8.6			11.9			16.1			23.2
Total	73.5			101.0			122.7			31.1			39.2			59.7			74.7
Operating data
Gross margin	$	27,099		$	48,582		$	69,945		$	13,420		$	18,689		$	24,848		$	37,027
Net income (loss)	(44,463		)	(33,249		)	(2,516		)	9,895		(A)	(5,619		)	(14,472		)	(15,372		)

(A) During the three-month period ended June 30, 2010 we recorded positive net income of approximately $9.9 million; however, this was primarily due to a non-cash gain of $16.6 million we recorded during the period related to the reduction in the fair market value of our Series I warrants.

Key trends in 2008, 2009, 2010 and the first six months of 2011. According to the U.S. Energy Information Administration, demand for natural gas fuels in the United States increased by approximately 26% during the period January 1, 2008 through December 31, 2010. We believe this growth in demand was attributable primarily to the rising prices of gasoline and diesel relative to CNG and LNG during these periods and increasingly stringent environmental regulations affecting vehicle fleets.

The number of fueling stations we served grew from 147 at December 31, 2004 to 248 at June 30, 2011 (a 68.7% increase). Included in this number are all of the CNG and LNG fueling stations we own, maintain or with which we have a fueling supply contract. The amount of CNG and LNG gasoline gallon equivalents we delivered from 2005 to 2010 increased by 116%. The increase in gasoline gallon equivalents delivered was the primary contributor 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.

During the last half of 2009, during 2010, and during the first six months of 2011, we experienced reduced margins related to our fueling business compared to historical margins. The reduction in margins is primarily a result of increased O&M volumes with our transit and refuse customers, that have lower margins, becoming a larger part of our overall fueling business. We believe that our margins on fuel sales will improve in the future to the extent we are successful in increasing our retail CNG and LNG fueling operations as an overall component of our fueling business. Within our overall fueling business, we earn our highest margins in our retail fueling operations.

During the first six months of 2011, prices for oil, gasoline, diesel fuel and natural gas generally increased. Oil prices fluctuated from a low of $92.19 per barrel in January 2011 to a high of $113.93 in April 2011 and settled at $95.42 per barrel on June 30, 2011. In California, average retail prices for gasoline have increased from a low of $3.36 per gallon in January 2011 to $3.89 per gallon at June 30, 2011, and average retail prices for diesel fuel have increased from a low of $3.51 per diesel gallon in January 2011 to $4.15 per diesel gallon at June 30, 2011. Higher gasoline and diesel prices typically improve our margins on fuel sales to the extent we price fuel at a discount to gasoline or diesel. During this time period, the price for natural gas slightly increased. The

Table of Contents

NYMEX price for natural gas fluctuated from a low of $3.79 per MMbtu in March 2011 to a high of $4.38 per MMbtu at May 2011. Our average retail prices for LNG fuel in the Los Angeles metropolitan area decreased from $2.50 per diesel gallon equivalent in January 2011 to $2.44 per diesel gallon equivalent at June 30, 2011, and our CNG fuel sold in the Los Angeles metropolitan area increased from a low of $2.60 per gasoline gallon equivalent in January 2011 to a high of $2.75 per gasoline gallon equivalent at June 30, 2011.

Anticipated future trends. We anticipate that, over the long term, the prices for gasoline and diesel will continue to be higher than the price of natural gas as a vehicle fuel, and more stringent emissions requirements will continue to make natural gas vehicles an attractive alternative to traditional gasoline and diesel powered vehicles. Our belief that natural gas will continue, over the long term, to be a cheaper vehicle fuel than gasoline or diesel is based in part on the growth in U.S. natural gas production and supply. A 2008 Navigant Consulting, Inc. study indicates that as a result of new unconventional gas shale discoveries from 22 basins in the U.S., maximum estimates of total recoverable domestic reserves from producers have increased to equal 118 years of U.S. production at 2007 production levels. The study indicated a mean level of reserves equal to 88 years of supply at 2007 production levels. According to the report, shale gas production growth from only the major six shale resources in the U.S., plus the Marcellus shale, could reach 27 billion cubic feet per day and as high as 39 billion cubic feet per day by 2015. Navigant has also indicated that development of the shale resources base has resulted in a substantial surplus of natural gas compared to demand of as much as 11 billion cubic feet per day. These current surplus levels are 18% of annual average historical U.S. consumption levels of approximately 20 Tcf per year; providing sufficient gas supply to meet the requirements of all existing markets and to meet new market requirements. Based on analyst reports, we believe that there is a significant worldwide supply of natural gas relative to crude oil as well. According to the 2010 BP Statistical Review of World Energy, on a global basis, the ratio of proven natural gas reserves to 2009 natural gas production was 37% greater than the ratio of proven crude oil reserves to 2009 crude oil production. This analysis suggests significantly greater long term availability of natural gas than crude oil based on current consumption.

We believe there will be significant growth in the consumption of natural gas as a vehicle fuel among vehicle fleets, and our goal is to capitalize on this trend and enhance our leadership position as this market expands. With our recent acquisitions of IMW and Northstar, we are now a fully integrated provider of advanced compression technology, station-building and fueling. We have built natural gas fueling stations, and plan to build additional natural gas fueling stations, that will provide LNG to fleet vehicles at the Ports of Los Angeles and Long Beach and for other regional corridors throughout the United States. Further, we plan to enhance our market leadership position by using the proceeds of our July 2011 financing transaction with Chesapeake to build a network of LNG truck fueling stations to form the backbone of America’s natural gas highway. We also anticipate expanding our sales of CNG and LNG in the other markets in which we operate, including regional trucking, refuse hauling, airports and public transit. Consistent with the anticipated growth of our business, we also expect that our operating costs and capital expenditures will increase, primarily from the anticipated expansion of our station network or LNG production capacity, as well as the logistics of delivering more CNG and LNG to our customers. We also anticipate that we will continue to seek to acquire assets and/or businesses that are in the natural gas fueling infrastructure or biomethane production business that may require us to raise additional capital. Additionally, we have and will continue to increase our sales and marketing team and other necessary personnel as we seek to expand our existing markets and enter new markets, which will also result in increased costs. Further, we expect to experience increased competition from oil companies, station owners, industrial gas companies, natural gas utilities and other competitors who enter the market for CNG and LNG vehicle fuels, and we anticipate that increased competition will result in higher operating costs and capital expenditures.

Continuing high unemployment rates and reduced economic activity may reduce our opportunities to attract new fleet customers. Many governmental entities are experiencing significant budget deficits as a result of the economic recession and have been, and may continue to be, unable to invest in new natural gas vehicles for their transit or refuse fleets or may be compelled to reduce public transportation and services, or the prices they pay for these services, which would negatively affect our business.

Sources of liquidity and anticipated capital expenditures. Liquidity is the ability to meet present and future financial obligations either through operating cash flows, the sale or maturity of existing assets, or by the acquisition of additional funds through capital management. Historically, our principal sources of liquidity have consisted of cash provided by operations and financing activities.

Our business plan calls for approximately $44.5 million in capital expenditures from July 1, 2011 through the end of 2011, primarily related to construction of new fueling stations. This amount excludes (i) the capital expenditures related to LNG fueling station construction to be funded by the proceeds of our July 2011 financing transaction with Chesapeake, and (ii) the capital expenditures DCEMB will make at its landfill gas processing facility with the proceeds it received on March 31, 2011 when it completed its bond offering. We may also elect to invest additional amounts in expansion of our California LNG plant or for other acquisitions or investments in companies or assets in the natural gas fueling infrastructure, services and production industries, including biomethane production. At June 30, 2011, we had total cash and cash equivalents of $35.3 million, and we will need to raise additional capital as necessary to fund any expansion of our California LNG plant, acquisitions or other capital expenditures or investments that we cannot fund through available cash, our line of credit from PCB, or cash generated by operations. The timing and necessity of any future capital raise will depend on our rate of new station construction, which may be affected by any federal legislation that provides incentives for natural gas vehicle purchases and fuel use,

Table of Contents

any decision to expand our California LNG plant, and potential merger or acquisition activity. For more information, see “Liquidity and Capital Resources” and “Capital Expenditures” below. We may not be able to raise capital on terms that are favorable to existing stockholders or at all. Any inability to raise capital may impair our ability to invest in new stations, develop natural gas fueling infrastructure and invest in strategic transactions or acquisitions, and reduce our ability to grow our business and generate increased revenues.

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

Operations

We generate revenues principally by selling CNG and LNG and providing O&M services to our vehicle fleet customers. For the six months ended June 30, 2011, CNG and biomethane (together) represented 69% and LNG represented 31% of our natural gas sales (on a gasoline gallon equivalent basis). To a lesser extent, we generate revenues by designing and constructing fueling stations and selling or leasing those stations to our customers. We also generate material revenues through sales of biomethane produced by our joint venture subsidiary DCE, sales of natural gas vehicle systems by our wholly owned subsidiary BAF, sales of advanced natural gas fueling compressors and related equipment and maintenance services through IMW, and sales of LNG and LCNG fueling station design, construction and O&M services through Northstar. The significant portion of our operating and maintenance revenues are generated from CNG stations, and substantially all of our station sale and leasing revenues have been generated from CNG stations.

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. CNG sales revenues based on an index-plus methodology increase or decrease as a result of an increase or decrease in the price of natural gas. We also sell a small amount of CNG under fixed-price contracts. We will continue to offer fixed price contracts as appropriate and consistent with our natural gas hedging policy that was revised in May 2008. Our fleet customers typically are billed monthly based on the volume of CNG sold at a station. The remainder of our CNG sales are on a per fill-up basis at prices we set at the pump based on prevailing market conditions. These customers typically pay using a credit card at the station.

LNG Sales

We sell substantially all of our LNG to fleet customers, who typically own and operate their fueling stations. We also sell LNG to customers at our five public LNG stations and for non-vehicle use. During 2011, we procured 42% of our LNG from third-party producers, and we produced the remainder of the LNG at our liquefaction plants in Texas and California. For LNG that we purchase from third parties, we may 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. LNG sales revenues based on an index-plus methodology increase or decrease as a result of an increase or decrease in the price of natural gas. We will continue to offer fixed price contracts as appropriate and consistent with our natural gas hedging policy that was revised in May 2008. Our LNG contracts provide that we charge our customers periodically based on the volume of LNG supplied or sold.

America’s Natural Gas Highway

We plan to build a network of LNG fueling stations at strategic truck stop locations along major trucking corridors in the United States. We anticipate that these fueling stations will form the backbone of America’s natural gas highway, and expect to use the proceeds of our July 2011 financing transaction with Chesapeake to help fund the cost of building the stations. We expect to generate revenue through sales of LNG to operators of heavy duty trucks and other vehicles at these planned fueling stations.

Government Incentives

Since October 1, 2006, we have received a federal fuel tax credit (“VETC”) of $0.50 per gasoline gallon equivalent of CNG and $0.50 per liquid gallon of LNG that we sold as vehicle fuel. Based on the service relationship with our customers, either we or our customers were able to claim the credit. We recorded these tax credits as revenues in our consolidated statements of operations as the credits are fully refundable and do not need to offset tax liabilities to be received. As such, the credits are not deemed income tax credits under the accounting guidance applicable to income taxes. In addition, we believe the credits are properly recorded as revenue because we often incorporate the tax credits into our pricing with our customers, thereby lowering the actual price per gallon we charge them. The program providing for the VETC expires on December 31, 2011.

On July 15, 2010, the IRS sent us a letter (i) disallowing approximately $5.1 million related to certain claims we made from October 1, 2006 to June 30, 2008 under the Volumetric Excise Tax Credit program, and (ii) seeking repayment of such amount. We have appealed the IRS’s determination, and on April 19, 2011, we participated in an examination appeal meeting with the IRS. We believe our claims were properly made and expect to continue to contest the IRS’s determination.

Table of Contents

Operation and Maintenance

We generate a significant 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. We include the volume of fuel dispensed at the stations at which we provide O&M services in our calculation of aggregate gasoline gallon equivalents sold. Through Northstar, we also generate O&M revenues for LNG fueling stations. In these instances, we may or may not also supply LNG to 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.

On December 15, 2010, we completed the purchase of Northstar, an entity that provides design, engineering, construction and maintenance services for LNG and LCNG fueling stations. For the six months ended June 30, 2011, Northstar contributed approximately $5.7 million to our revenue.

Vehicle Acquisition and Finance

In 2006, we commenced offering vehicle finance services for some of our customers’ purchases of natural gas vehicles or the conversion of their existing gasoline or diesel powered vehicles to operate on natural gas. We loan to certain qualifying customers a portion of, and on occasion up to 100% of, the purchase price of their natural gas vehicles. We may also lease vehicles in the future. Where appropriate, we apply for and receive state and federal incentives associated with natural gas vehicle purchases and pass these benefits through to our customers. We may also secure vehicles to place with customers or pay deposits with respect to such vehicles prior to receiving a firm order from our customers, which we may be required to purchase directly if our customer fails to purchase the vehicle as anticipated. Through June 30, 2011, we have not generated significant revenue from vehicle finance activities.

Landfill Gas

In August 2008, we acquired 70% of the outstanding membership interests of DCE for a purchase price of $19.6 million including transaction costs. DCE owns a facility that collects, processes and sells biomethane from the McCommas Bluff landfill located in Dallas, Texas. For the six months ended June 30, 2010 and 2011, DCE generated approximately $5.8 million and $5.9 million, respectively, in revenue from sales of biomethane, all of which is included in our condensed consolidated statements of operations.

On April 3, 2009, DCE entered into a fifteen year gas sale agreement with Shell Energy North America (US), L.P. (“Shell”) for the sale by DCE to Shell of biomethane produced by DCE’s landfill gas processing facility (the “Shell Gas Sale Agreement”).

DCE retains the right to reserve from the Shell Gas Sale Agreement up to 500 MMBtus per day of biomethane for sale as a vehicle fuel. To the extent that DCE produces volumes of biomethane in excess of the volumes sold under the agreement, DCE will either attempt to sell such volumes at then-prevailing market prices or seek to enter into another gas sale agreement in the future. There is no guarantee that DCE will produce or be able to sell up to the maximum volumes called for under the agreement, and DCE’s ability to produce such volumes of biomethane is dependent on a number of factors beyond DCE’s control including, but not limited to, the availability and composition of the landfill gas that is collected, the impact on DCE’s operations of the operation of the landfill by the City of Dallas and the reliability of the processing plant’s critical equipment. The processing equipment is currently being expanded and upgraded, which may result in significant down time to complete the work, which consequently may reduce DCE’s sales of biomethane during the period of expansion and upgrade work. The expansion and upgrade work is anticipated to continue into the first half of 2012.

The sale price for the gas under the Shell Gas Sale Agreement is fixed. The sale price for the gas represents a substantial premium to the current prevailing prices for natural gas at June 30, 2011.

The Shell Gas Sale Agreement is terminable by either party on thirty days’ written notice if the California Energy Commission makes a written determination or adopts a ruling or regulation that the biomethane sold under the agreement will, from the date of such ruling or regulation, no longer qualify as a California Renewable Portfolio Standard eligible fuel. In addition, Shell has the right to terminate the agreement upon thirty days’ written notice if the volumes of biomethane produced and delivered, calculated monthly on a rolling two-year average, are less than an annual average of 630,720 MMBtu per year (or 2,083 MMBtu per day).

Table of Contents

On March 25, 2011, DCE’s subsidiary, Dallas Clean Energy McCommas Bluff, LLC, a Delaware limited liability company (“DCEMB”), arranged for a $40.2 million tax-exempt bond issuance (the “Revenue Bonds”). The Revenue Bonds will be repaid from the revenue generated by DCEMB from the sale of renewable natural gas (or biomethane). The Revenue Bonds are secured by the revenue and assets of DCEMB and are non-recourse to DCEMB’s direct and indirect parent companies, including us. The bond repayments are amortized through December 2024 and the average coupon interest rate on the bonds is 6.60%. The bond issuance closed March 31, 2011.

The bond proceeds will primarily be used to finance further improvements and expansion of the DCEMB landfill gas processing facility. A portion of the proceeds were used to retire the DCE Loan. The Company, in turn, used the proceeds from the payoff of the DCE Loan to repay approximately $8.0 million we owed to PCB under the Facility B Loan on March 31, 2011.

Pursuant to the Loan Agreement, dated as of January 1, 2011 (the “Loan Agreement”), between DCEMB and the Mission Economic Development Corporation (the “Issuer”), DCEMB has covenanted with the Issuer to make loan repayments equal to the principal and interest coming due on the Revenue Bonds. Pursuant to the Trust Indenture, dated as of January 1, 2011 (the “Indenture”), the Issuer has pledged and assigned to the Trustee all of the Issuer’s right, title and interest in and to the Loan Agreement (with certain specified exceptions) and the Note described below. DCEMB executed a promissory note, dated March 31, 2011 (the “Note”), as evidence of its obligations under the Loan Agreement.

The obligations of DCEMB under the Loan Agreement are secured by a Leasehold Deed of Trust, Assignment of Rents, Security Agreement and Fixture Filing, dated as of January 1, 2011 (the “Deed of Trust”), executed by DCEMB in favor of the deed of trust trustee named therein for the benefit of the Bank of New York Mellon Trust Company, N.A., a Trustee (the “Trustee”). In addition, DCEMB executed a Security Agreement (the “Security Agreement”), as security for its obligations, pursuant to which DCEMB granted to the Trustee a security interest in all right, title and interest of DCEMB to the Collateral (as defined in the Security Agreement), which includes, but is not limited to, DCEMB’s rights, title and interest in any gas sale agreements, including the Shell Gas Sale Agreement, and the funds and accounts held under the Indenture.

Pursuant to a Consent and Agreement, by and between Shell Energy, The Bank of New York Mellon Trust Company, N.A., as Depository Bank, (the “Depository Bank”), DCEMB and the Trustee, dated as of January 1, 2011 (the “Consent Agreement”), Shell Energy agreed to make all payments due to DCEMB under the Shell Gas Sale Agreement to the Depository Bank. In addition, other revenues generated through the sale of gas produced at the facility will be paid directly to the Depository Bank pursuant to a Depository and Control Agreement, dated as of January 1, 2011 (the “Depository Agreement”), among DCEMB, the Trustee and the Depository Bank.

All payments received by the Depository Bank will be placed into various accounts in accordance with the requirements of the Indenture and the Depository Agreement. The funds in these accounts will be used to service required debt payments, finance further improvements and expansion of the landfill gas processing facility owned by DCEMB, finance the operations and maintenance of DCEMB, finance certain expenses associated with setting up and maintaining the accounts, and other uses as prescribed in the Depository Agreement. The Depository Bank will make payments out of these accounts in accordance with the requirements of the Depository Agreement. At the end of each month after all required account fundings have been fulfilled in accordance with the Depository Agreement, all remaining excess funds will be placed into a Surplus Account. The funds in the Surplus Account will be delivered to DCEMB so long as (i) DCEMB’s Debt Service Coverage Ratio (as defined) for the most recent four calendar quarters then ended equals or exceeds 1.25:1, (ii) DCEMB’s Debt Service Coverage Ratio (as defined) is reasonably projected to equal or exceed 1.25:1 for the next four calendar quarters, (iii) no events of default have occurred as defined by the Indenture and the Loan Agreement, and (iv) after giving effect to the transfer, DCEMB’s Minimum Days Cash on Hand (as defined) shall be, or shall at any time be projected to be, more than the lesser of thirty-five Days Cash on Hand (as defined) or $1.3 million. Due to these restrictions on this cash, we have classified all of this cash as restricted cash on the balance sheet. We record the restricted cash that is expected to be received and used within the next 12 months from the Depository Bank for working capital and operating purposes as current in our balance sheet, and present the remaining balance as non-current in the line item notes receivable and other long term assets. At June 30, 2011, $23.0 million was included as long term assets and $3.2 million was included in restricted cash in the accompanying condensed consolidated balance sheet.

The Indenture and the Loan Agreement have certain non-financial debt covenants with which DCEMB must comply. As of June 30, 2011, DCEMB was in compliance with all such debt covenants.

Table of Contents

Vehicle Conversions

On October 1, 2009, we purchased all of the outstanding shares of BAF. Founded in 1992, BAF provides natural gas vehicle (“NGV”) conversions, alternative fuel systems, application engineering, service and warranty support and research and development services. BAF’s vehicle conversions include taxis, vans, pick-up trucks and shuttle buses. BAF utilizes advanced natural gas system integration technology and has certified NGVs under both EPA and CARB standards achieving Super Ultra Low Emission Vehicle emissions. We generate revenues through the sale of natural gas vehicle conversion systems that allow gasoline and diesel vehicles to run on natural gas. The majority of BAF’s revenue during 2010 was derived from sales of converted natural gas service vans to AT&T and Verizon. During the first six months of 2010 and 2011, BAF contributed approximately $20.0 million and $12.6 million, respectively, to our revenue.

Natural Gas Fueling Compressors

On September 7, 2010, we completed our purchase of IMW. IMW manufactures and services advanced, non-lubricated natural gas fueling compressors and related equipment for the global natural gas fueling market. IMW is headquartered near Vancouver, British Columbia, has a second manufacturing facility near Shanghai, China and has sales and service offices in Bangladesh, Columbia, Peru and the United States. For the six months ended June 30, 2011, IMW contributed approximately $30.8 million to our revenue.

Volatility of Earnings and Cash Flows

Our earnings and cash flows historically have fluctuated significantly from period to period based on our futures activities, as all of our futures contracts entered into prior to June 30, 2008 have not qualified for hedge accounting under the relevant derivative accounting guidance. We have therefore recorded any changes in the fair market value of these contracts that did not qualify for hedge accounting directly in our statements of operations in the line item derivative (gains) losses along with any realized gains or losses generated during the period. We experienced a derivative loss of $0.3 million in the year ended December 31, 2008. Subsequent to June 30, 2008, our futures contracts did qualify for hedge accounting, so we had no derivative gains or losses in the years ended December 31, 2009 and 2010 and during the six month period ended June 30, 2011 related to our futures contracts. In accordance with our natural gas hedging policy, we plan to structure all subsequent futures contracts as cash flow hedges under the applicable derivative accounting guidance, 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 contracts. Futures contracts are valued daily, and if our contracts are in loss positions at the end of a trading day, our broker will transfer the amount of the losses from our margin account to a clearinghouse. If at any time the funds in our margin account drop below a specified maintenance level, our broker will issue a margin call that requires us to restore the balance. Consequently, these payments could significantly impact our cash balances. At June 30, 2011, we had $3.6 million on deposit in margin accounts, which are included in prepaid expenses and other current assets and notes receivable and other long-term assets in our balance sheet.

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.

Volatility of Earnings Related to Series I Warrants

Beginning January 1, 2009, under Financial Accounting Standards Board (“FASB”) authoritative guidance, we have been required to record the change in the fair market value of our Series I warrants in our consolidated financial statements. We recognized a loss (gain) of $2.0 million and $(1.5) million related to recording the fair market value changes of our Series I warrants in the six months ended June 30, 2010 and 2011, respectively. See note 17 to our condensed consolidated financial statements contained elsewhere herein. Our earnings or loss per share may be materially impacted by future gains or losses we are required to record as a result of valuing our Series I warrants. On November 10, 2010, 1,183,712 of the Series I warrants were exercised and are no longer outstanding. As of June 30, 2011, 2,130,682 of the Series I warrants remained outstanding.

Volatility of Earnings Related to Contingent Consideration

Under recent business combination accounting guidance, we are required to record the change in the value of the contingent consideration related to our acquisitions of both BAF and IMW in our financial statements through the contingency period, which expires December 31, 2011 for BAF and March 31, 2014 for IMW.

Table of Contents

If the anticipated results of BAF or IMW increase or decrease during future periods, we may be required to recognize material losses or gains based on the valuation of the increased or decreased consideration due to the former BAF and IMW shareholders. To record the change in value of the BAF contingent consideration, we recognized a loss of $0.5 million during the six months ended June 30, 2010 and we recognized a gain of $0.1 million during the six months ended June 30, 2011. To record the change in the value of the IMW contingent consideration, we recognized a gain of $0.6 million during the six months ended June 30, 2011.

Debt Compliance

Our credit agreement with PCB (“Credit Agreement”) requires us to comply with certain covenants. We may not incur indebtedness or liens except as permitted by the Credit Agreement, or declare or pay dividends. We must maintain, on a quarterly basis, minimum liquidity of not less than $6.0 million, accounts receivable balances, as defined, of not less than $8.0 million, consolidated net worth, as defined, of not less than $150.0 million, and a debt to equity ratio, as defined, of not more than 0.3 to 1.0. Beginning in the quarter ended June 30, 2009, we must also maintain a debt service ratio, as defined, of not less than 1.5 to 1.0 at each quarter end. In computing these amounts, we exclude the financial results and amounts of IMW. Effective in the fourth quarter of 2008, we established a lock-box arrangement with PCB subject to the Credit Agreement. Funds received from certain customers are remitted to the lock-box and then deposited to a PCB bank account. The remitted funds are not used to pay-down the balance of the Credit Agreement unless there is an event of default on the Credit Agreement. One of the events of default is the occurrence of a “material adverse change,” which is a subjective acceleration clause. Based on the relevant accounting guidance, we have classified our debt pursuant to the Credit Agreement as short-term or long-term, as appropriate, and we believe the likelihood of an event of default is more than remote, but not more likely than not. If we default on the Credit Agreement, all of the obligations under the Credit Agreement will become immediately due and payable and all funds received in our lockbox held by PCB, plus $2.5 million we have deposited with PCB in a payment reserve account, will be applied to the balance due on the Credit Agreement. To the extent natural gas prices continue to fall, our volumes decline or our operating results do not materialize as planned, we could violate our covenants in the future. In the event we violate our covenants, we would seek a waiver from the bank, which the bank is not obligated to grant. We were in compliance with all of our covenants as of June 30, 2011.

Pursuant to our acquisition of IMW, our credit agreement with HSBC also requires that IMW complies with certain financial covenants as detailed in note 11 of our condensed consolidated financial statements contained elsewhere herein. Among those financial covenants are that IMW shall not permit 1) its ratio of debt to tangible net worth to be greater than 3.25 to 1.0 until December 31, 2010, and greater than 4.0 to 1.0 from January 1, 2011 through June 30, 2011, and greater than 3.0 to 1.0 on or after July 1, 2011, 2) its tangible net worth to at anytime be below CAD$3,000 and 3) its ratio of current assets to current liabilities to be less than 1.15 to 1.0 until December 31, 2010 and less than 1.25 to 1.0 on or after January 1, 2011. Should IMW’s operating results not materialize as planned, we could violate these covenants. If we were to violate a covenant, we would seek a waiver from the bank, which the bank is not obligated to grant. If the bank were to decline to grant a waiver, all of the obligations under the credit agreement would be due and payable. IMW was in compliance with these covenants as of June 30, 2011.

The Indenture and the Loan Agreement DCEMB entered into as part of issuing its Revenue Bonds have certain non-financial debt covenants that DCEMB must comply with. As of June 30, 2011, DCEMB was in compliance with its debt covenants.

Risk Management Activities

Our risk management activities, including the revised natural gas hedging policy adopted by our board of directors in February 2007 and revised by our board of directors on May 29, 2008, are discussed in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operation) of our 2010 Annual Report on Form 10-K. For the quarter ended June 30, 2011, there were no material changes to our risk management activities.

Critical Accounting Policies

For the six months ended June 30, 2011, there were no material changes to the “Critical Accounting Policies” discussed in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) of our 2010 Annual Report on Form 10-K.

Recently Issued Accounting Pronouncements

For a description of recently issued accounting pronouncements, see note 18 to our condensed consolidated financial statements contained elsewhere herein.

Table of Contents

Results of Operations

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2011		2010		2011
Statement of Operations Data:
Revenue:
Product revenues	89.6		89.0		88.8		89.3
Service revenues	10.4		11.0		11.2		10.7
Total revenues	100.0		100.0		100.0		100.0
Operating expenses:
Cost of sales:
Product cost of sales	65.2		67.8		65.3		67.5
Service cost of sales	4.4		5.1		4.8		5.0
Derivative (gains) losses on Series I warrant valuation	(37.7	)	(7.0	)	2.4		(1.1	)
Selling, general and administrative	33.8		31.4		34.3		29.5
Depreciation and amortization	11.5		11.0		12.1		11.0
Total operating expenses	77.2		108.3		118.9		111.9
Operating income (loss)	22.8		(8.3	)	(18.9	)	(11.9	)
Interest income (expense), net	(0.1	)	(2.2	)	0.1		(1.7	)
Other income (expense), net	(0.1	)	0.3		—		0.6
Income from equity method investments	0.1		0.2		0.1		0.2
Income (loss) before income taxes	22.7		(10.0	)	(18.7	)	(12.8	)
Income tax (expense) benefit	(0.2	)	1.7		1.4		1.4
Net income (loss)	22.5		(8.3	)	(17.3	)	(11.4	)
Loss (income) attributable to noncontrolling interest	(0.2	)	0.2		(0.1	)	(0.1	)
Net income (loss) attributable to Clean Energy Fuels Corp.(A)	22.3		(8.1	)	(17.4	)	(11.5	)

(A) During the three-month period ended June 30, 2010, we recorded positive net income of approximately $9.9 million; however, this was primarily due to a non-cash gain of $16.6 million we recorded during the period related to the reduction in the fair market value of our Series I warrants.

Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010

Revenue. Revenue increased by $25.1 million to $69.1 million in the three months ended June 30, 2011, from $44.0 million in the three months ended June 30, 2010. A portion of this increase was the result of an increase in the number of gallons delivered from 31.1 million gasoline gallon equivalents to 39.2 million gasoline gallon equivalents. Our increase in CNG volume was primarily from six new refuse customers, four new stations for an existing transit customer and one new airport customer, which together accounted for 5.0 million gallons of the CNG volume increase. These CNG volume increases were offset by a 3.3 million gallon decrease related to the loss of two transit customers. We also experienced an increase of 3.3 million gallons in LNG volume between periods, which was primarily due to 3.4 million gallons from Northstar O&M services. We experienced a $2.9 million increase, excluding Northstar, in station construction revenues between periods, primarily due to the completion of two new CNG stations for two refuse customers and the sale of a CNG station upgrade to one of our existing transit customers. Our acquisitions of IMW on September 7, 2010 and Northstar on December 15, 2010 contributed $14.0 million and $2.0 million, respectively, to our increased revenue between periods. Revenue attributable to the VETC also increased between periods as we recorded $4.7 million of revenue related to fuel tax credits. We did not record any revenue related to fuel tax credits in the second quarter of 2010 as the fuel tax credits were not reinstated until the fourth quarter of 2010. These increases were offset by the decrease in our effective price per gallon that we charged to our customers between periods. Our effective price per gallon was $0.87 in the three months ended June 30, 2011, which represents a $0.11 per gallon decrease from $0.98 in the three months ended June 30, 2010. The decrease was primarily due to a higher percentage of O&M contracts in the second quarter of 2011, which generate less revenue per gallon than contracts where we supply the natural gas commodity. Revenue also decreased by $2.0 million between periods due to decreased sales of natural gas vehicle equipment by BAF.

Table of Contents

Cost of sales. Cost of sales increased by $19.8 million to $50.4 million in the three months ended June 30, 2011, from $30.6 million in the three months ended June 30, 2010. Our cost of sales primarily increased between periods as a result of delivering more volume to our customers. Our acquisition of IMW on September 7, 2010 and Northstar on December 15, 2010 contributed $13.8 million and $1.4 million, respectively, to our increased cost of sales between periods. We also experienced a $2.4 million increase, excluding Northstar, in station construction costs between periods. These increases were offset by the decrease in our effective cost per gallon of $0.04 per gallon, to $0.62 per gallon, in the three months ended June 30, 2011. This decrease was primarily the result of a higher percentage of O&M contracts in the second quarter of 2011 that are included in our volume totals but do not increase our cost of sales amount significantly as we do not pay for the natural gas consumed at the properties. We also experienced a $1.7 million decrease in costs related to BAF’s vehicle equipment sales between periods, as BAF’s sales of natural gas vehicle equipment decreased.

Derivative (gain) loss on Series I warrant valuation. Derivative gain decreased by $11.8 million to a $4.8 million gain in the three months ended June 30, 2011, from $16.6 million in the three months ended June 30, 2010. The amounts represent the non-cash impact attributable to valuing our outstanding Series I warrants based on the required mark-to-market accounting for the warrants (see note 17 to our condensed consolidated financial statements contained elsewhere herein) during the three month period ended June 30, 2011.

Selling, general and administrative. Selling, general and administrative expenses increased by $6.8 million to $21.7 million in the three months ended June 30, 2011, from $14.9 million in the three months ended June 30, 2010. A significant portion of this increase was the result of our salaries and benefits expense increasing by $3.2 million between periods as we increased our employee headcount from 274 at June 30, 2010 to 829 (including the addition of 481 IMW and 28 Northstar employees) at June 30, 2011. We also experienced a $2.0 million increase in occupancy costs, business insurance, employee recruiting, and general office expenses related to our continued business growth and our acquisitions of IMW and Northstar during the third and fourth quarters of 2010. In addition, our marketing expenses increased $0.7 million between periods due to certain advertising we conducted in the regional trucking, refuse and transit markets to support our continued business growth. Stock option expense between periods increased $0.5 million, primarily due to the stock options issued in 2011 to new employees. Our travel and entertainment expenses increased $0.5 million between periods, primarily due to the increased travel of our sales team. Offsetting these increases was a decrease of $0.2 million as we did not record any additional IMW and BAF contingent consideration liabilities during the second quarter of 2011, compared to a $0.2 million increase in the BAF contingent consideration liability during the second quarter of 2010.

Depreciation and amortization. Depreciation and amortization increased by $2.5 million to $7.6 million in the three months ended June 30, 2011, from $5.1 million in the three months ended June 30, 2010. This increase was primarily due to additional depreciation expense in the three months ended June 30, 2011 related to increased property and equipment balances between periods, primarily related to our expanded station network. Our June 30, 2011 amortization expense also includes increased amortization of the intangible assets we obtained in connection with our acquisition of IMW in the third quarter of 2010 and Northstar in the fourth quarter of 2010.

Interest income (expense), net. Interest income (expense), net, increased by $1.5 million to $1.5 million of expense for the three months ended June 30, 2011. This increase was primarily the result of an increase in interest expense in the three months ended June 30, 2011 related to debt we incurred in connection with the acquisition of IMW, and interest expense related the DCEMB’s revenue bonds since April 1, 2011 (see note 11 to our condensed consolidated financial statements contained elsewhere herein).

Other income (expense), net. Other income (expense), net, increased by $0.2 million to $0.2 million of income for the three months ended June 30, 2011. This increase was primarily due to the impact of foreign currency exchange gains on the notes we issued as part of the IMW acquisition.

Income from equity method investment. During the three months ended June 30, 2011, we recorded equity income of $0.2 million related to our 49% interest in our Peruvian joint venture, and for the three months ended June 30, 2010, we recorded income of $0.0 million related to our interest.

Income (loss) of noncontrolling interest. During the three months ended June 30, 2011, we recorded $0.1 million for the noncontrolling interest in the net loss of DCEMB compared to $0.1 million for the noncontrolling interest in the net income of DCEMB for the three months ended June 30, 2010. The noncontrolling interest represents the 30% interest in DCEMB held by our joint venture partner.

Table of Contents

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Revenue. Revenue increased by $51.5 million to $134.5 million in the six months ended June 30, 2011, from $83.0 million in the six months ended June 30, 2010. A portion of this increase was the result of an increase in the number of gallons delivered from 59.7 million gasoline gallon equivalents to 74.7 million gasoline gallon equivalents. Our increase in CNG volume was primarily from eight new refuse customers, five new stations for an existing transit customer, two new transit customers and one new airport customer, which together accounted for 11.6 million gallons of the CNG volume increase. The volume growth from our existing airport, refuse, transit and public fueling network, combined with the volume growth from our share of our joint venture in Peru, contributed 3.5 million gallons of the CNG volume increase. These CNG volume increases were offset by a 6.6 million gallon decrease related to the loss of two transit customers. We also experienced an increase of 7.1 million gallons in LNG volume between periods, which was primarily due to 6.5 million gallons from Northstar O&M services. The volume growth from two new refuse customers, combined with the increase from our port trucking customers, contributed to the remaining LNG volume increase. We experienced a $9.1 million increase, excluding Northstar, in station construction revenues between periods, primarily due to the completion of six new CNG stations for two refuse customers and the sale of a CNG station upgrade to one of our existing transit customers. Our acquisitions of IMW on September 7, 2010 and Northstar on December 15, 2010 contributed $30.8 million and $5.7 million, respectively, to our increased revenue between periods. Revenue attributable to VETC also increased between periods as we recorded $8.9 million of revenue related to fuel tax credits. We did not record any revenue related to fuel tax credits in the second quarter of 2010 as the fuel tax credits were not reinstated until the fourth quarter of 2010. These increases were offset by the decrease in our effective price per gallon that we charged to our customers between periods. Our effective price per gallon was $0.86 in the six months ended June 30, 2011, which represents a $0.15 per gallon decrease from $1.01 in the six months ended June 30, 2010. The decrease was primarily due to a higher percentage of O&M contracts in the first six months of 2011, which generate less revenue per gallon than contracts where we supply the natural gas commodity. Revenue also decreased by $7.4 million between periods due to decreased sales of natural gas vehicle equipment by BAF.

Cost of sales. Cost of sales increased by $39.2 million to $97.4 million in the six months ended June 30, 2011, from $58.2 million in the six months ended June 30, 2010. Our cost of sales primarily increased between periods as a result of delivering more volume to our customers. Our acquisition of IMW on September 7, 2010 and Northstar on December 15, 2010 contributed $28.8 million and $4.0 million, respectively, to our increased cost of sales between periods. We also experienced a $7.5 million increase, excluding Northstar, in station construction costs between periods. These increases were offset by the decrease in our effective cost per gallon of $0.08 per gallon, to $0.62 per gallon, in the six months ended June 30, 2011. This decrease was primarily the result of a higher percentage of O&M contracts in the first six months of 2011 that are included in our volume totals but do not increase our cost of sales amount significantly as we do not pay for the natural gas consumed at the properties. We also experienced a $5.7 million of decrease in costs related to BAF’s vehicle equipment sales between periods.

Derivative (gain) loss on Series I warrant valuation. Derivative (gain) loss increased by $3.5 million to a $1.5 million gain in the six months ended June 30, 2011, from a $2.0 million loss in the six months ended June 30, 2010. The amounts represent the non-cash impact attributable to valuing our outstanding Series I warrants based on the required mark-to-market accounting for the warrants (see note 17 to our condensed consolidated financial statements contained elsewhere herein) during the three month period ended June 30, 2011.

Selling, general and administrative. Selling, general and administrative expenses increased by $11.2 million to $39.7 million in the six months ended June 30, 2011, from $28.5 million in the six months ended June 30, 2010. A significant portion of this increase was the result of our salaries and benefits expense increasing by $5.9 million between periods as we increased our employee headcount from 274 at June 30, 2010 to 829 (including the addition of 481 IMW and 28 Northstar employees) at June 30, 2011. We also experienced a $3.6 million increase in occupancy costs, business insurance, employee recruiting, bank and credit card fees, information technology maintenance, training and seminars, and general office expenses related to our continued business growth and our acquisitions of IMW and Northstar during the third and fourth quarters of 2010. Stock option expense between periods increased $0.9 million, primarily due to the stock options issued in 2011 to new employees. Our travel and entertainment expenses increased $0.8 million between periods, primarily due to the increased travel of our sales team. Our professional fees increased $0.6 million between periods, primarily for legal, audit and consulting services related to our continued business growth. In addition, our marketing expenses increased $0.5 million between periods due to certain advertising we conducted in the regional trucking, refuse and transit markets related to our continued business growth. Offsetting these increases was a decrease of $1.2 million during the first six months of 2011 related to a decrease in the IMW and BAF contingent consideration liabilities.

Depreciation and amortization. Depreciation and amortization increased by $4.7 million to $14.8 million in the six months ended June 30, 2011, from $10.1 million in the six months ended June 30, 2010. This was primarily due to additional depreciation expense in the six months ended June 30, 2011 related to increased property and equipment balances between periods, primarily related to our expanded station network. Our June 30, 2011 amortization expense also includes increased amortization of the intangible assets we obtained in connection with our acquisition of IMW in the third quarter of 2010 and Northstar in the fourth quarter of 2010.

Table of Contents

Interest income (expense), net. Interest income (expense), net, increased by $2.4 million, from $0.1 million of income for the six months ended June 30, 2010, to $2.3 million of expense for the six months ended June 30, 2011. This increase was primarily the result of an increase in interest expense in the six months ended June 30, 2011 related to debt we incurred in connection with the acquisition of IMW, and interest expense related the DCEMB’s revenue bonds since April 1, 2011 (see note 11 to our condensed consolidated financial statements contained elsewhere herein.).

Other income (expense), net. Other income (expense), net, increased by $0.8 million to $0.8 million of income in the six months ended June 30, 2011. This increase was primarily due to the impact of foreign currency exchange gains on the notes we issued as part of the IMW acquisition.

Income from equity method investments. During the six months ended June 30, 2011, we recorded equity income of $0.4 million related to our 49% interest in our Peruvian joint venture, and for the six months ended June 30, 2010, we recorded income of $0.1 million related to our interest.

Income (loss) of noncontrolling interest. During the six months ended June 30, 2011, we recorded $0.2 million for the noncontrolling interest in the net income of DCEMB, compared to $0.1 million for the noncontrolling interest in the net income of DCEMB for the six months ended June 30, 2010. The noncontrolling interest represents the 30% interest in DCE held by our joint venture partner.

Seasonality and Inflation

To some extent, we experience seasonality in our results of operations. Natural gas vehicle fuel amounts 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, repairs, maintenance, electricity 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 or materially increase our operating costs.

Liquidity and Capital Resources

Historically, our principal sources of liquidity have consisted of cash provided by operations and financing activities. At June 30, 2011, we had total cash and cash equivalents of $35.3 million, compared to $55.2 million at December 31, 2010.

We currently have a $20 million line of credit (“LOC”) from PCB that expires August 14, 2011, but we have a one year renewal option we can exercise as long as we are not in default on the covenants contained in the Credit Agreement. As of June 30, 2011, we did not have any balance outstanding under the LOC.

Table of Contents

Our credit agreement with PCB requires that we comply with certain covenants, as detailed in note 11 of our condensed consolidated financial statements contained elsewhere herein. One of the covenants requires that we maintain accounts receivable balances from certain subsidiaries above $8.0 million at each quarter-end during the term. To the extent natural gas prices fall, which would result in decreased revenues, or our volumes sold decline, we could violate this covenant. Also, beginning with the quarter ending June 30, 2009, we have been required to maintain a debt service ratio, as defined, of 1.5 to 1. Should our operating results not materialize as planned, we could violate this covenant. If we were to violate a covenant, we would seek a waiver from the bank, which the bank is not obligated to grant. If the bank does not grant a waiver, all of the obligations under the credit agreement will become immediately due and payable and $2.5 million of our funds held by PCB would be applied to the balance due on the PCB loans. We also would be unable to use the $20 million PCB line of credit if this were to occur. We were in compliance with all of the covenants as of June 30, 2011.

On July 11, 2011, we entered into a Loan Agreement (the “Loan Agreement”) with Chesapeake NG Ventures Corporation (“Chesapeake”), an indirect wholly owned subsidiary of Chesapeake Energy Corporation, whereby Chesapeake agreed to purchase from us up to $150 million aggregate principal amount of debt securities for the development, construction and operation of liquefied natural gas stations (the “Note Financing”) pursuant to the issuance of three convertible promissory notes, each having a principal amount of $50 million (each a “Note” and collectively the “Notes”). Chesapeake Energy Corporation guaranteed Chesapeake’s commitment to purchase the Notes under the Loan Agreement.

The first Note was issued on July 11, 2011, and we expect to issue the second and third Notes on June 29, 2012 and June 28, 2013, respectively. The Notes bear interest at the rate of 7.5% per annum (payable quarterly, in arrears, on March 31, June 30, September 30 and December 31 of each year, beginning on September 30, 2011) and are convertible at Chesapeake’s option into shares of our common stock (the “Shares”) at $15.80 per share. Subject to certain restrictions, we can force conversion of each Note into Shares if, following the second anniversary of the issuance of a Note, the Shares trade at a 40% premium to the Conversion Price for at least twenty trading days in any consecutive thirty trading day period. The entire principal balance of each Note is due and payable seven years following its issuance, and we may repay each Note in Shares or cash. The Loan Agreement restricts the use of the Note Financing proceeds to financing the development, construction and operation of liquefied natural gas stations and payment of certain related expenses. The Loan Agreement also provides for customary events of default which, if any of them occurs, would permit or require the principal of and accrued interest on the Notes to become or to be declared due and payable.

In addition to funding operations, our principal uses of cash have been, and are expected to be, the construction of new fueling stations, construction of LNG production facilities, the purchase of new LNG tanker trailers, investment in biomethane production, mergers and acquisitions, 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, support of legislative initiatives and for working capital for our expansion. We have also acquired and may continue to seek to acquire and invest in companies or assets in the natural gas and biomethane fueling infrastructure, services and production industries. We financed our operations in the first six months of 2011 primarily through cash on hand, cash provided by operating activities and cash provided by financing activities.

Cash provided by operating activities was $9.9 million for the six months ended June 30, 2011, compared to cash used in operating activities of $4.0 million for the six months ended June 30, 2010. The increase in operating cash flow resulted primarily from the cash received during the first six months of 2011 related to the volumetric excise tax credit of approximately $17.7 million. This amount represents the entire credit amount for 2010 as the credit expired December 31, 2009 and was reinstated in the fourth quarter of 2010 and made retroactive to January 1, 2010. This increase was offset by changes in working capital balances due to timing differences related to various cash flows between periods.

Cash used in investing activities was $59.9 million for the six months ended June 30, 2011, compared to $17.6 million for the six months ended June 30, 2010. Our purchases of property and equipment were $27.6 million during the first six months of 2011, and $17.4 million during the six months of 2010. We made additional investments during the first six months of 2011 totaling $1.5 million in the Vehicle Production Group, LLC (“VPG”), a company developing a CNG taxi and a paratransit vehicle, and we did not make any additional investments in VPG during the first six months of 2010. We also invested $1.2 million for a 19.9% interest in ServoTech Engineering, Inc. (“ServoTech”), a company that provides design and engineering services for natural gas fueling systems, among other services, during the six months ended June 30, 2011. Also during the six months ended June 30, 2011, as part of the DCEMB bond offering, we placed $26.2 million of cash into restricted accounts to be used for the capital expenditures of DCEMB.

Cash provided by financing activities for the six months ended June 30, 2011 was $31.0 million, compared to $10.3 million for the six months ended June 30, 2010. This increase is primarily due to the DCEMB bond offering of $40.2 million for the expansion of the landfill gas processing facility owned by DCEMB that closed on March 31, 2011. Additionally, we received net proceeds from borrowings under our HSBC line of credit of $5.3 million to finance the working capital needs at IMW. These proceeds were offset by $9.9 million we paid on March 31, 2011 to pay off our Facility B Loan, and the cash payment of $5.0 million we made as part of the first IMW Note payment owed as part of the acquisition of IMW. Additionally we received net proceeds of $0.7 million from the exercise of employee stock options in the six months ended June 30, 2011, compared to $10.5 million for the six months ended June 30, 2010.

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, our capital expenditure requirements (which consist primarily of station construction, LNG plant construction costs, biomethane plant construction costs and the purchase of LNG tanker trailers and equipment) and any merger or acquisition activity.

Capital Expenditures

Table of Contents

expenditures DCEMB will make at its landfill gas processing facility with the proceeds it received on March 31, 2011 when it completed its bond offering. We may also elect to invest additional amounts in expansion of our California LNG plant or for other acquisitions or investments in companies or assets in the natural gas fueling infrastructure, services and production industries, including biomethane production. At June 30, 2011, we had cash and cash equivalents of $35.3 million, and we will need to raise additional capital as necessary to fund any of the aforementioned activities or other capital expenditures or investments that we cannot fund through available cash, our line of credit from PCB, the potential exercise of a warrant for 15,000,000 shares of our common stock at an exercise price of $10 per share held by Boone Pickens, or cash generated by operations. The timing and necessity of any future capital raise will depend primarily on our rate of new station construction, which may be affected by any federal legislation that provides incentives for natural gas vehicle purchases and fuel use, any decision to expand our California LNG plant and potential merger or acquisition activity. We may not be able to raise capital on terms that are favorable to existing stockholders or at all. Any inability to raise capital may impair our ability to invest in new stations, expand our California LNG plant, develop natural gas fueling infrastructure and invest in strategic transactions or acquisitions, and reduce the ability of our business to grow and generate increased revenues.

Off-Balance Sheet Arrangements

At June 30, 2011, we had the following off-balance sheet arrangements that had, or are reasonably likely to have, a material effect on our financial condition:

· outstanding surety bonds for construction contracts and general corporate purposes totaling $79.0 million,

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

· operating leases where we are the lessee,

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

· firm commitments to sell CNG and LNG at fixed prices.

We provide 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 our surety bonds as we do not believe, based on historical experience and information currently available, that it is probable that any amounts will be required to be paid under these arrangements for which we will not be reimbursed.

We have entered into two contracts that require us to purchase minimum volumes of LNG. One contract expires in June 2014 and the other contract expires in October 2017.

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 built our California LNG liquefaction plant. The lease is for an initial term of thirty years and requires payments of $0.2 million per year, plus up to $0.1 million per year for each 30 million gallons of production capacity utilized, 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 a fee for certain other services that the landlord will provide.

We are also the lessor in various leases with our customers, whereby our customers lease certain stations and equipment that we own.

Item 3.—Quantitative and Qualitative Disclosures about Market Risk

In the ordinary course of business, we are exposed to various market risk factors, including changes in general economic conditions, domestic and foreign competition, commodity price risk and foreign currency exchange rates.

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 natural gas price increases through 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.

Table of Contents

Natural gas costs represented 30% (or 33% excluding BAF, IMW and Northstar) of our cost of sales for 2010 and 24% (or 45% excluding BAF, IMW and Northstar) of our cost of sales for six months ended June 30, 2011. Prices for natural gas over the eleven-year and six month period from December 31, 1999 through June 30, 2011, based on the NYMEX daily futures data, have ranged from a low of $1.65 per Mcf to a high of $19.38 per Mcf. At June 30, 2011, the NYMEX index price of natural gas was $4.33 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 FASB authoritative guidance on derivatives. The accounting under this guidance for changes in the fair value of a derivative depends upon whether it has been specified 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.

The fair value of the futures contracts we use is based on quoted prices in active exchange traded or over the counter markets which are then discounted to reflect the time value of money for contracts applicable to future periods. The fair value of these futures contracts is continually subject to change due to market conditions. In an effort to mitigate the volatility in our earnings related to futures activities, 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 this guidance, 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 the futures contracts we hold as of June 30, 2011 to hedge the fixed price component of certain supply contracts. If the price of natural gas were to fluctuate (increase or decrease) by 10% from the price quoted on NYMEX on June 30, 2011 ($4.33 per MMbtu), we could expect a corresponding fluctuation in the value of the contracts of approximately $0.6 million.

Foreign exchange rate risk. Because we have foreign operations, we are exposed to foreign currency exchange gains and losses. Since the functional currency of our foreign operations is in their local currency, the currency effects of translating the financial statements of those foreign subsidiaries, which operate in local currency environments, are included in the accumulated other comprehensive income (loss) component of consolidated equity and do not impact earnings. However, foreign currency transaction gains and losses not in our subsidiaries’ functional currency do impact earnings and resulted in approximately $0.8 million of gains in the six months ended June 30, 2011. During the six months ended June 30, 2011, our primary exposure to foreign currency rates related to our Canadian operations that had certain outstanding notes payable denominated in the U.S. dollar that were not hedged.

We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to our monetary transactions denominated in a foreign currency. If the exchange rate on these assets and liabilities were to fluctuate by 10% from the rate as of June 30, 2011, we would expect a corresponding fluctuation in the value of the assets and liabilities of approximately $1.9 million.

Item 4.—Controls and Procedures

Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities, and migrating processes.

Table of Contents

There were no changes in our internal control over financial reporting that occurred during the period covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II.—OTHER INFORMATION

Item 1.—Legal Proceedings

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

Item 1A.—Risk Factors

An investment in our Company involves a high degree of risk of loss. You should carefully consider the risk factors discussed below and all of the other information included in this report before you decide to purchase shares of our common stock. We believe the risks and uncertainties described below are the most significant we face. The occurrence of any of the following risks could harm our business. In that case, the trading price of our common stock could decline. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also impair our operations.

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

For the six month period ended June 30, 2011, we incurred pre-tax losses of $17.1 million, which included derivative gains of $1.5 million related to marking to market the value of our Series I warrants. During the six month period ended June 30, 2011, our loss was decreased by our receipt of approximately $8.9 million of revenue from federal fuel tax credits. In 2008, 2009 and 2010, we incurred pre-tax losses of $44.3 million, $33.4 million, and $4.2 million, respectively. Our loss for 2008 includes $18.6 million in expenses associated with our support for Proposition 10, the California Alternative Fuel Vehicles and Renewable Energy ballot initiative; our loss for 2009 includes $17.4 million of derivative losses related to marking to market the value of our Series I warrants; and our loss for 2010 was decreased by a derivative gain of $10.3 million on our Series I warrants. During 2008, 2009 and 2010, our losses were substantially decreased by our receipt of approximately $17.2 million, $15.5 million and $16.0 million of revenue from federal fuel tax credits, respectively. In order to execute our strategy and improve our financial performance, we must continue to invest in developing the natural gas vehicle fuel market and offer our customers compelling natural gas fuel prices. If we do not achieve or maintain profitability that can be sustained in the absence of federal fuel tax credits, our business will suffer and the price of our common stock may drop. In addition, if the price of our common stock increases during future periods when our Series I warrants are outstanding, we may be required to recognize material losses based on the valuation of the outstanding Series I warrants.

A material portion of our historical revenues are associated with a federal fuel excise tax credit that expires on December 31, 2011.

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, expires December 31, 2011. Based on the service relationship we have with our customers, either we or our customers are able to claim the credit. For the six month period ended June 30, 2011, we recorded approximately $8.9 million related to fuel tax credits, representing approximately 6.6% of our total revenue. In 2008, 2009 and 2010, we recorded approximately $17.2 million, $15.5 million and $16.0 million of revenue, respectively, related to fuel tax credits, representing approximately 13.7%, 11.8% and 7.6%, respectively, of our total revenue during the periods. On July 15, 2010, the IRS sent us a letter disallowing approximately $5.1 million related to certain excise tax credit claims that we made from October 1, 2006 to June 30, 2008. If we are unsuccessful in appealing the IRS disallowance of these claims, we may be required to refund some or all of the $5.1 million in contested claims.

Table of Contents

We will need to raise debt or equity capital to continue to fund the growth of our business.

We will be required to raise debt or equity capital to fund the growth of our business. At June 30, 2011, we had total cash and cash equivalents of $35.3 million, and our business plan calls for approximately $44.5 million in capital expenditures from July 1, 2011 through the end of 2011. This amount excludes (i) the capital expenditures related to LNG fueling station construction to be funded by the proceeds of our July 2011 financing transaction with Chesapeake, and (ii) the capital expenditures DCEMB will make at its landfill gas processing facility with the proceeds it received on March 31, 2011 when it completed its bond offering. We may also require capital for unanticipated expenses, mergers and acquisitions and strategic investments. In addition, we have committed to significant future payments that we will be required to make in connection with our acquisition of IMW and Northstar. At June 30, 2011, our future payments for IMW and Northstar totaled $37.5 million and $7.5 million, respectively. Also, at June 30, 2011, we were obligated to pay up to $40.0 million as additional consideration related to our IMW acquisition if certain performance measurements of IMW are met and up to $11.0 million as additional consideration related to our BAF acquisition if certain performance measurements of BAF are met.

Equity or debt financing options may not be available on terms favorable to us or at all, particularly if there are no effective federal incentives supporting the growth of the natural gas fueling business. Additional sales of our common stock or securities convertible into our common stock will dilute existing stockholders and may result in a decline in our stock price. We may also pursue debt financing options including, but not limited to, equipment financing, the sale of convertible promissory notes or commercial bank financing. Recent economic turmoil and severe lack of liquidity in the debt capital markets and volatility in the equity capital markets have adversely affected capital raising opportunities. If we are unable to obtain debt or equity financing in amounts sufficient to fund any unanticipated expenses, capital expenditures, mergers, acquisitions or strategic investments, we will be forced to suspend or curtail these capital expenditures or postpone or delay potential acquisitions or other strategic transactions, which would harm our business, results of operations, and future prospects.

We are required to make substantial future payments to Chesapeake.

On July 11, 2011, we entered into the Loan Agreement with Chesapeake, whereby Chesapeake agreed to purchase from us up to $150 million aggregate principal amount of debt securities pursuant to the issuance of three convertible promissory notes, each having a principal amount of $50 million (each a “Note” and collectively the “Notes”). The first Note was issued on July 11, 2011, and we expect to issue the second and third Notes on June 29, 2012 and June 28, 2013, respectively. The Notes bear interest at the rate of 7.5% per annum (payable quarterly, in arrears, on March 31, June 30, September 30 and December 31 of each year, beginning on September 30, 2011). The entire principal balance of each Note is due and payable seven years following its issuance, and we may repay each Note in common stock or cash. For the period July 11, 2011 through December 31, 2011, we expect our interest payment obligations under the Notes to be approximately $1.8 million. In future periods, we may not have sufficient capital resources to enable us to fulfill our payment obligations to Chesapeake. If we are unable to make scheduled payments or comply with the other provisions of the documents relating to the Notes, Chesapeake may be permitted under certain circumstances to accelerate the maturity of the Notes and exercise other remedies provided for in the Notes and under applicable law. An acceleration of the maturity of the Notes that is not rescinded would have a material adverse effect on our company.

Our growth is influenced by tax and related government incentives for clean burning fuels and alternative fuel vehicles. A reduction in these incentives or the failure to pass new legislation with new incentive programs will increase the cost of natural gas fuel and vehicles for our customers and may reduce our revenue.

Our business is influenced by 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 income tax credit that was available to offset 50% to 80% of the incremental cost of purchasing new or converted natural gas vehicles expired on December 31, 2010. The absence of these vehicle tax credits could have a detrimental effect on the natural gas vehicle and fueling industry, including sales at our wholly owned subsidiary, BAF, and adversely affect our results of operations and financial performance. Our business plan and the ability of our business to successfully grow depends in part on the extension of the federal fuel excise tax credit for natural gas vehicle fuel, the reinstatement and extension of the federal income tax credit for the purchase of natural gas vehicles and the passage of legislation providing for additional incentives for the sale and use of natural gas vehicles. If existing federal incentives are not reinstated or extended and if new incentives are not passed, fewer natural gas vehicles will be sold and used and our revenue and financial performance will be adversely affected. Furthermore, the failure of certain federal, state or local government incentives which promote the use of natural gas as a vehicle fuel to pass into law could result in a negative perception by the market generally and a decline in the market price of our common stock. In addition, if grant funds are no longer available under existing government programs for the purchase and construction of natural gas vehicles and stations, the purchase of natural gas vehicles and station construction could slow and our business and results of operations will be adversely affected. Continued reduction in tax revenues associated with high unemployment rates, economic recession or slow-down could result in a significant reduction in funds available for government grants that support vehicle conversion and station construction, which could impair our ability to grow our business.

Table of Contents

Challenges we may encounter managing our growth may divert resources and limit our ability to successfully expand our operations.

We have been and continue to be engaged in a period of rapid and substantial growth, which places a strain on our operational infrastructure and imposes significant added responsibilities on members of our management. Our ability to manage our operations and growth effectively requires us to continue to hire, train and integrate necessary personnel to further develop our operational, financial and management controls, expand and improve our financial reporting and legal compliance systems and manage our natural gas station construction, maintenance and operations projects. If we are not able to effectively manage our business growth in a cost-effective manner, our operating results, sales and revenues may be negatively impacted.

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

Limited availability of natural gas vehicles and engine sizes for heavy duty vehicles restricts their wide scale introduction and narrows our potential customer base. 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 major automobile manufacturer that currently makes natural gas powered passenger vehicles, and major manufacturers of medium and heavy duty vehicles currently produce only a narrow range and number of natural gas vehicles. The technology utilized in some of the heavy duty vehicles that run on LNG is also relatively new and has not been previously deployed or used in large numbers of vehicles. As a result, these vehicles may require servicing and further technology refinements to address performance issues that may occur as vehicles are deployed in large numbers and are operated under strenuous conditions. If potential heavy duty LNG truck purchasers are not satisfied with truck performance, additional heavy-duty truck engine manufacturers do not enter the market for LNG engines, or LNG engines are not otherwise developed, produced and adopted in greater numbers, our LNG fueling business may be delayed, impaired, or eliminated, which would adversely affect our financial performance. Further, North American car and truck manufacturers are facing significant economic challenges that may make it difficult or impossible for them to introduce new natural gas vehicles in the North American market or continue to manufacture and support the limited number of available natural gas vehicles. Due to the limited supply of natural gas vehicles, our ability to promote natural gas vehicles and our natural gas fuel sales may be restricted, even if there is demand.

We May Not be Successful in Executing our LNG Fueling Station Strategy.

Our current business plan calls for us to develop LNG truck fueling stations at strategic truck stop locations along major trucking corridors in the United States. Failure to execute this strategy may adversely affect our financial results and business. Our strategy to develop LNG fueling stations may not be successful for many reasons, including:

· We may have difficulty identifying and obtaining sufficient rights to use suitable locations for LNG fueling stations;

· We may have insufficient resources to develop planned stations;

· We may experience delays in building stations, including delays in obtaining necessary permits and approvals;

· Heavy duty natural gas engines may not be adopted at all or may be adopted at a rate that is slower than our expectations due to, among other things, failure by manufacturers to develop and produce such engines, performance issues relating to such engines and the cost of such engines;

· We may have difficulty sourcing and transporting sufficient LNG;

· LNG may not be an attractive alternative to diesel fuel in the future.

Decreases in the price of oil, gasoline and diesel fuel may slow the growth of our business and negatively impact our financial results.

Recent increases in prices for oil, gasoline and diesel fuel have resulted in increased interest in alternative fuels such as CNG and LNG. However, any decline in the price of oil, diesel fuel and gasoline may result in reduced interest in CNG and LNG, which would slow the growth of our business. In addition, to the extent that we price our CNG and LNG fuel at a discount to these reduced diesel or gasoline prices in an effort to attract new and retain existing customers, our profit margin on fuel sales may be harmed and our financial results negatively impacted. Further, lower fuel prices for CNG and LNG as a result of lower natural gas commodity prices also will reduce our revenues.

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, 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. Our ability to offer CNG and LNG fuel to our customers at lower prices than gasoline and

Table of Contents

diesel depends in part on natural gas prices remaining lower, on an energy equivalent basis, than oil prices. If the price of oil declines and the price of natural gas increases, it will make it more difficult for us to offer our customers discounted prices for CNG and LNG as compared to gasoline and diesel prices and maintain an acceptable margin on our sales. Recent and significant volatility in oil and gasoline prices demonstrate that it is difficult to predict future transportation fuel costs. In addition, any new regulations imposed on natural gas extraction in the United States, particularly on extraction of natural gas from shale formations, could increase the costs of domestic gas production or make it more costly to produce natural gas in the United States, which could lead to substantial increases in the price of natural gas. Reduced prices for gasoline and diesel fuel, combined with higher costs for natural gas and natural gas vehicles, may cause potential customers to delay or reject converting their fleets to run on natural gas. In that event, our sales of natural gas fuel and vehicles would be slowed and our business would suffer.

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

In the recent past, the price of natural gas has been volatile, and this volatility may continue. From the end of 1999 through December 31, 2010, 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. At June 30, 2011, the NYMEX index price for natural gas was $4.33 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 an effective futures contract in place that fully mitigates the price risk or where we otherwise cannot pass the increased costs on to our customers. In addition, higher natural gas prices may cause CNG and LNG to cost as much as or more than gasoline and diesel generally, which would adversely impact the adoption of CNG and LNG as a vehicle fuel and our business. Conversely, lower natural gas prices reduce our revenues due to the fact that in a significant amount of our customer agreements, the commodity cost is passed through to the customer. 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, negative publicity surrounding drilling techniques, level of consumer demand, economic conditions, price of foreign natural gas imports, and domestic and foreign governmental regulations and political conditions. In particular, there have been recent legislative efforts to place new regulatory requirements on the production of natural gas by hydraulic fracturing of shale gas reservoirs. Hydraulic fracturing of shale gas reservoirs has resulted in a substantial increase in the proven natural gas reserves in the United States, and any changes in regulations that make it more expensive or unprofitable to produce natural gas through hydraulic fracturing could lead to increased natural gas prices. The recent economic recession and increased domestic natural gas supplies have contributed to significant declines in the price of natural gas since the summer of 2008.

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

Our business depends in part on environmental regulations and programs in the United States that promote or mandate the use of cleaner burning fuels, including natural gas for vehicles. 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. Further, economic difficulties may result in the delay, amendment or waiver of environmental regulations due to the perception that they impose increased costs on the transportation industry that cannot be absorbed in a contracting economy. For example, the Clean Trucks Program at the Ports of Los Angeles and Long Beach formerly called for the replacement of a set number of drayage trucks with “clean” trucks, but due to economic conditions and other factors, the Clean Trucks Program no longer calls for any specific number of “clean” truck replacements. In addition, many of the clean trucks that have been deployed have been clean diesel trucks which are generally less expensive than LNG trucks. There have also been recent ballot initiatives in the State of California and lawsuits aimed at postponing or delaying California’s implementation of AB 32, also known as the Global Warming Solutions Act of 2006, which is intended to reduce greenhouse gas emissions. CNG, LNG and biomethane vehicle fuel all produce lower greenhouse gas emissions than gasoline or diesel fuel and the delay or repeal of AB 32, and in particular California’s low-carbon fuel standard, could reduce the appeal of natural gas fuel for our customers and reduce our revenue. The delay, repeal or modification of federal or state regulations or programs that encourage the use of cleaner vehicles could also have a detrimental effect on the United States natural gas vehicle industry, which, in turn, could slow our growth and adversely affect our business.

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, our ability to supply CNG and LNG at competitive prices and acceptance of our technology, fuel systems or services. A decline in oil, diesel fuel and gasoline prices may result in decreased interest in alternative fuels like CNG and LNG. In addition, there is reduced availability of

Table of Contents

debt financing as compared to prior years to support the purchase of CNG and LNG vehicles and investment in CNG and LNG infrastructure. If our potential customers are unable to access credit to purchase natural gas vehicles, it may make it difficult or impossible for them to invest in natural gas vehicle fleets, which would impair the ability of our business to grow. Further, potential customers may not find our technology, fuel systems or services acceptable.

Our global operations expose us to additional risk and uncertainties.

We have operations in a number of countries, including the United States, Canada, China, Colombia, Bangladesh and Peru. In addition to the other risks described herein, our global operations may be subject to risks and uncertainties that may limit our ability to operate our business. Our natural gas compression equipment is primarily manufactured in Canada and sold globally, which exposes us to a number of risks that can arise from international trade transactions, local business practices and cultural considerations, including:

· political unrest, terrorism and economic or financial instability;

· unexpected changes in regulatory requirements and uncertainty related to developing legal and regulatory systems governing economic and business activities, real property ownership and application of contract rights;

· import-export regulations;

· difficulties in enforcing agreements and collecting receivables;

· difficulties in ensuring compliance with the laws and regulations of multiple jurisdictions;

· difficulties in ensuring that health, safety, environmental and other working conditions are properly implemented and/or maintained by the local office;

· changes in labor practices, including wage inflation, labor unrest and unionization policies;

· limited intellectual property protection;

· local competitors misappropriating our product designs;

· longer payment cycles by international customers;

· currency exchange fluctuations;

· inadequate local infrastructure and disruptions of service from utilities or telecommunications providers, including electricity shortages;

· potentially adverse tax consequences; and

· differing employment practices and labor issues.

We also face risks associated with currency exchange and convertibility, inflation and repatriation of earnings as a result of our foreign operations. In some countries, economic, monetary and regulatory factors could affect our ability to convert funds to U.S. dollars or move funds from accounts in these countries. We are also vulnerable to appreciation or depreciation of foreign currencies against the U.S. dollar. We do not currently engage in currency hedging activities to limit the risks of currency fluctuations.

We may not be successful in managing or integrating IMW into our business, which could prevent us from realizing the expected benefits of the acquisition and could adversely affect our future results.

The integration of IMW into our business presents significant challenges and risks to our business, including (i) the distraction of management from other business concerns, (ii) the retention of customers of IMW, (iii) expansion into foreign markets, (iv) the introduction of IMW’s compressor and related equipment manufacturing and servicing business, which is a new product line for us, (v) achievement of appropriate internal controls over financial reporting and (vi) the monitoring of compliance with all laws and regulations. The vast majority of IMW’s revenue is derived from sales in emerging markets, and IMW has not previously been required to comply with the U.S. Foreign Corruption Practices Act or any of the requirements of Sarbanes-Oxley. If we do not

Table of Contents

successfully integrate IMW into our business and maintain regulatory compliance, we may not realize the benefits expected from the acquisition and our results of operations could be materially adversely affected. If the revenue of IMW declines or grows more slowly than we anticipate, or if its operating expenses are higher than we expect, we may not be able to achieve, sustain or increase the growth of our business, in which case our financial condition will suffer and our stock price could decline. In addition, the operations of IMW do not have the disclosure controls and procedures or internal controls over financial reporting that are as thorough or effective as those required for a public company. Although we intend to implement appropriate controls and procedures as we integrate the operations of IMW, we cannot provide assurance as to the effectiveness of the disclosure controls and procedures or internal controls over financial reporting of IMW until we have fully integrated them.

A significant portion of the purchase price of IMW was allocated to goodwill and a write-off of all or part of this goodwill could adversely affect our operating results.

Under business combination accounting standards, we allocated the total purchase price of IMW to its net tangible assets and liabilities and intangible assets based on their fair values as of the date of the acquisition and recorded the excess of the purchase price over those values as goodwill. Our estimates of the fair value of the assets and liabilities of IMW were based upon certain assumptions, including assumptions about and anticipated attainment of new business, believed to be reasonable, but which are inherently uncertain. Pursuant to the applicable accounting standards, we allocated $45.0 million of the purchase price for IMW to goodwill. Our goodwill could be impaired if developments affecting the acquired compressor manufacturing operations or the markets in which IMW produces and/or sells compressors lead us to conclude that the cash flows we expect to derive from its manufacturing operations will be substantially reduced. An impairment of all or part of our goodwill could adversely affect our results of operations and financial condition.

We may not be successful in managing or integrating our recently acquired subsidiary, Northstar, with our existing operations.

On December 15, 2010 we acquired Northstar, a leading provider of design, engineering, construction and maintenance services for LNG and LCNG fueling stations. Our ability to realize benefits from the acquisition depends on the growth of the LNG fueling market and our ability to successfully integrate Northstar’s business with our existing operations. We cannot provide any assurances that the LNG fueling market, or Northstar’s business, will grow or that we will successfully manage the integration of Northstar’s business with our existing operations. In addition, the Northstar operations do not have the disclosure controls and procedures or internal controls over financial reporting that are as thorough or effective as those required for public companies. Although we intend to implement appropriate controls and procedures as we integrate the Northstar operations, we cannot provide assurance as to the effectiveness of Northstar’s disclosure controls and procedures or internal controls over financial reporting until we have fully integrated them.

DCEMB’s failure to comply with the terms of its bond financing agreements would impair our rights in DCEMB.

In connection with the issuance of the Revenue Bonds, DCEMB entered into, among other documents, the Loan Agreement, the Note, the Deed of Trust and the Security Agreement (collectively the “Bond Agreements”). Pursuant to the Bond Agreements, DCEMB is subject to certain covenants, including a requirement to make loan repayments on the Revenue Bonds. This repayment obligation is secured by a security interest in all of the Collateral (as defined in the Security Agreement), which includes, but is not limited to, DCEMB’s rights, title and interest in any gas sale agreements and the funds and accounts held under an indenture. If DCEMB defaults on its obligation to make loan repayments on the Revenue Bonds, the Issuer or the Trustee may, among other things, take whatever action at law or in equity as may be necessary or desirable to ensure loan repayments are made on the Revenue Bonds. If the Issuer or the Trustee take any such actions, or if DCEMB otherwise fails to comply with its covenants and other obligations under the Bond Agreements, our rights in DCEMB would be impaired, and our business and results of operations may be adversely affected.

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. A prolonged economic recession or disruption in the capital markets may make it difficult or impossible to obtain necessary financing to expand the natural gas vehicle fueling infrastructure and impair our ability to grow our business. 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.

Table of Contents

We have significant contracts with federal, state and local government entities that are subject to unique risks.

We have existing, and will continue to seek, long-term CNG and LNG station construction, maintenance and fuel sales contracts with various federal, state and local governmental bodies, which accounted for approximately 68% of our annual revenues in 2006 and approximately 41% of our annual revenues in 2010. In May and June 2009, we spent $5.6 million to acquire four new CNG operation and maintenance contracts with government agencies. In addition to our normal business risks, our contracts with these government entities are often subject to unique risks, some of which are beyond our control. Long-term government contracts and related orders are subject to cancellation if appropriations for subsequent performance periods are not made. The termination of funding for a government program supporting any of our CNG or LNG operations could result in a loss of anticipated future revenues attributable to that program, which could have a negative impact on our operations. In addition, government entities with whom we contract are often able to modify, curtail or terminate contracts with us without prior notice at their convenience, and are only liable for payment for work done and commitments made at the time of termination. Modification, curtailment or termination of significant contracts could have a material adverse effect on our results of operations and financial condition. In particular, if any of the contracts we recently acquired are terminated, we may be unable to recover our investment in acquiring the contracts. During the fourth quarter of 2010, we lost one of the acquired contracts in a competitive procurement, which resulted in a charge of $1.5 million related to the impairment of an intangible asset originally recorded with the acquisition.

Further, government contracts are frequently awarded only after competitive bidding processes, which have been and may continue to be protracted. For example, the Metropolitan Transit System of San Diego, which represented approximately 6.0 million of the gallons of CNG we sold in 2009, conducted a competitive bidding procurement and awarded the contract to a competitor on July 27, 2010. The Washington Metropolitan Area Transit Authority, which represented approximately 6.3 million of the gallons of CNG we sold in 2010, also conducted a competitive bidding procurement which resulted in the award of that contract to a competitor on December 31, 2010. In many cases, unsuccessful bidders for government agency contracts are provided the opportunity to formally protest certain contract awards through various agencies, administrative and judicial channels. The protest process may substantially delay a successful bidder’s contract performance, result in cancellation of the contract award entirely and distract management. We may not be awarded contracts for which we bid, and substantial delays or cancellation of purchases may even follow our successful bids as a result of such protests.

The budget deficits being experienced by many governmental entities may reduce the available funding for certain natural gas programs and services and the purchase of CNG or LNG fuel, which could reduce our revenue and impair our financial performance.

Many governmental entities are experiencing significant budget deficits as a result of the economic recession, which has and may continue to reduce or curtail their ability to fund natural gas fuel programs, purchase natural gas vehicles or provide public transportation and services, which would harm our business. Furthermore, in response to budget deficits, such governmental entities have and may continue to request or demand that we lower our price for CNG or LNG fuel.

Conversion of vehicles to run on natural gas is time-consuming and expensive and may limit the growth of our sales.

Conversion of vehicle engines from gasoline or diesel to natural gas is performed by only a small number of vehicle conversion suppliers (including our wholly owned subsidiary, BAF) that must meet stringent safety and engine emissions certification standards. The engine certification process is time consuming and expensive and raises vehicle costs. In addition, conversion of vehicle engines from gasoline or diesel to natural gas may result in vehicle performance issues or increased maintenance costs that could discourage our potential customers from purchasing converted vehicles that run on natural gas and impair the financial performance of BAF. Without an increase in vehicle conversion options, reduced vehicle conversion costs and improved vehicle conversion performance, our sales of natural gas vehicle fuel and converted natural gas vehicles, through BAF, may be restricted and our revenue will be reduced both by less demand for natural gas vehicle fuel and less demand for converted natural gas vehicles.

A majority of BAF’s sales of CNG vehicles are to one customer. If this customer does not continue to purchase CNG vehicles, then revenue at our wholly owned subsidiary, BAF, will decline and our financial results will be impaired.

During 2009 and 2010, BAF derived approximately 63% and 66%, respectively, of its revenue from AT&T. AT&T is not required to purchase any CNG vehicle conversion kits under its agreement with BAF and the agreement and all purchase orders submitted by AT&T under the agreement may be cancelled by AT&T at any time for any reason. If AT&T does not continue to order and pay for CNG vehicle conversion kits produced by BAF, then BAF’s sales revenue will substantially decline and our financial performance may suffer. AT&T has ordered fewer vehicles in the first six months of 2011 compared to the first six months of 2010, and has indicated that it may reduce or delay conversion of additional vehicles during the last half of 2011 in order to allow for a build-out of infrastructure to support fueling the vehicles. In the absence of continued sales to AT&T, BAF will experience materially reduced revenues and may require additional cash to continue its operations, which could drain our capital resources.

Table of Contents

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, more 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 fuel, may slow the need to diversify fuels and affect the growth of the natural gas vehicle market. In addition, a prototype heavy duty electric truck model was recently introduced at the ports of Los Angeles and Long Beach. Use of electric heavy duty trucks or the perception that electric heavy duty trucks may soon be widely available and provide satisfactory performance in heavy duty applications may reduce demand for heavy duty LNG trucks. In addition, 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 that 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 our ability to compete with other alternative fuels and alternative fuel vehicles.

Our ability to supply LNG to new and existing customers is restricted by limited production of LNG and by our ability to acquire 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. It may become difficult for us to obtain additional LNG without interruption and near our current or target markets at competitive prices. If our LNG liquefaction plants, or any of those from which we purchase LNG, are damaged by severe weather, earthquake or other natural disaster, or otherwise experience prolonged downtime, our LNG supply will be restricted. Currently, one of the suppliers from whom we obtain LNG has experienced unscheduled plant shut downs and has been unable to maintain minimum production levels on a consistent basis, which has caused us to incur additional costs to obtain LNG from other sources. 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. Our growth plans, if successful, will require substantial growth in the available LNG supply across the United States, and if this supply is unavailable, it will constrain our ability to increase the market for LNG fuel including supplying LNG fuel to heavy duty truck customers. If we experience an LNG supply interruption or LNG demand that exceeds available supply, or if we have difficulty entering or maintaining relationships with contract carriers, our ability to expand LNG sales to new customers will be limited, our relationships with existing customers may be disrupted, and our results of operations may be adversely affected. Furthermore, because transportation of LNG is relatively expensive, if we are required to supply LNG to our customers from distant locations and cannot pass these costs through to our customers, our operating margins will decrease on those sales due to our increased transportation costs.

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

Two of our LNG supply agreements have a take-or-pay commitment and our California LNG liquefaction plant has a land lease and other fixed operating costs regardless of production and sales levels. The take-or-pay commitments require us to pay for the LNG that we have agreed to purchase irrespective of whether we can sell the LNG to our own customers. For example, the LNG Sales Agreement that we entered into with Desert Gas Services (“DGS”) on October 17, 2007 has a ten year term and, provided that Plant Capacity (as defined in the LNG Sales Agreement) is available to be taken by us, the plant is not shut down by DGS and no event beyond our reasonable control prevents us from taking delivery of LNG, we are committed to purchasing at least 45,000 gallons of LNG per day. Should the market demand for LNG decline, or if we lose significant LNG customers or if demand under any existing or any future LNG supply contract does not maintain its volume levels or grow, overall operating and supply costs may increase as a percentage of revenue and negatively impact our margins.

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 natural gas prices. We have in the past experienced LNG supply disruptions due to severe weather in the Gulf of Mexico and plant outages. If there are interruptions in field production, insufficient pipeline capacity, equipment failure on liquefaction production or delivery delays, 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.

Table of Contents

Oil companies, station owners, industrial gas 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 vehicle fuels. Many of these potential entrants, such as integrated oil companies, industrial gas companies, and natural gas utilities, have far greater resources and brand awareness than we have. Natural gas utilities, particularly in California, continue to own and operate natural gas fueling stations that compete with our stations. Utilities in Michigan, Illinois, New Jersey and Georgia have also recently made efforts to invest in the natural gas vehicle fuel space. If the use of natural gas vehicles and demand for natural gas vehicle fuel increases, these companies may find it more attractive to enter or expand their operations in the market for natural gas vehicle fuels and we may experience increased pricing pressure, reduced operating margins and fewer expansion opportunities.

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

From 2005 to 2008, we sold and delivered approximately 30% 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. Effective January 1, 2007, we no longer offer contracts with a price cap to our customers, though, from time to time we still enter into contracts with various customers to sell CNG or LNG at fixed prices. At any given time, 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 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, our policy has been to purchase futures contracts to hedge our exposure to natural gas price variability related to our fixed price contracts. Such contracts, however, may not be available or we may not have sufficient financial resources to secure such contracts. In addition, under our hedging policy, we may reduce or remove futures contracts we have in place related to these contracts if such disposition is approved in advance by our board of directors and derivative committee. If we are not effectively 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, 2011, we were economically hedged with respect to our fixed price contracts with our customers.

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

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

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

We are required to maintain a margin account to cover losses related to our natural gas futures contracts. Futures contracts are valued daily, and if our contracts are in loss positions at the end of a trading day, our broker will transfer the amount of the losses from our margin account to a clearinghouse. If at any time the funds in our margin account drop below a specified maintenance level, our broker will issue a margin call that requires us to restore the balance. Payments we make to satisfy margin calls will reduce our cash reserves, adversely impact our liquidity and may also adversely impact our ability to expand our business. Moreover, if we are unable to satisfy the margin calls related to our futures contracts, our broker may sell these contracts to restore the margin requirement at a substantial loss to us. As of June 30, 2011, we had $3.6 million on deposit related to our futures contracts.

If our futures contracts do not qualify for hedge accounting, our net income (loss) 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 the relevant derivative accounting guidance, which requires us to value our futures contracts at fair market value in our financial statements. Prior to June 2008, our futures contracts did not qualify 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. Currently, we attempt to qualify all of our futures contracts for hedge accounting under the relevant derivative accounting guidance, but there can be no assurances that we will be successful in doing so. At June 30, 2011, all of our futures contracts qualified for hedge accounting. To the extent that all or some of our futures contracts do not qualify for hedge accounting, we could incur significant

Table of Contents

increases and decreases in our net income (loss) and stockholders’ equity in the future based on fluctuations in the market value of our futures contracts from quarter to quarter. We had no derivative gains or losses related to our natural gas futures contracts for the year ended December 31, 2010 and for the six months ended June 30, 2011. 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.

Compliance with potential greenhouse gas regulations affecting our LNG plants or fueling stations may prove costly and negatively affect our financial performance.

California has adopted legislation, AB 32, which calls for a cap on greenhouse gas emissions throughout California and a statewide reduction to 1990 levels by 2020, and an additional 80% reduction below 1990 levels by 2050. Seven western U.S. states (Arizona, California, Montana, New Mexico, Oregon, Utah and Washington) and four Canadian provinces (British Columbia, Manitoba, Ontario and Quebec) formed the Western Climate Initiative to help combat climate change. Other states and the federal government are considering passing measures to regulate and reduce greenhouse gas emissions. Any of these regulations, when and if implemented, may regulate the greenhouse gas emissions produced by our LNG production plants in California and Texas or our CNG and LNG fueling stations and require that we obtain emissions credits or invest in costly emissions prevention technology. We cannot currently estimate the potential costs associated with federal or state regulation of greenhouse gas emissions from our LNG plants or CNG and LNG stations, and these unknown costs are not contemplated in the financial terms of our customer agreements. These unanticipated costs may have a negative impact on our financial performance and may impair our ability to fulfill customer contracts at an operating profit.

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

Natural gas fueling operations and vehicle conversions entail inherent risks, including equipment defects, malfunctions and failures and natural disasters, which could result in uncontrollable flows of natural gas, fires, explosions and other damages. For example, operation of LNG pumps requires special training and protective equipment because of the extreme low temperatures of LNG. LNG tanker trailers have also in the past been, and may in the future be, involved in accidents that result in explosions, fires and other damage. Improper refueling of LNG vehicles can result in venting of methane gas, which is a potent greenhouse gas, and LNG related methane emissions may in the future be regulated by the EPA or by state regulations. Additionally, CNG fuel tanks, if damaged or improperly maintained, may rupture and the contents of the tank may rapidly decompress and result in death or injury. In 2007, a driver of a CNG van in Los Angeles was killed when the previously damaged tank he was fueling ruptured. 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. If CNG or LNG vehicles are perceived to be unsafe, it will harm our growth and negatively affect BAF’s ability to sell converted CNG vehicles, which would impair our financial performance.

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

Our operations to date have been concentrated in California and Arizona. For the years ended December 31, 2008, 2009 and 2010, sales in California accounted for 44%, 49% and 49% respectively, and sales in Arizona accounted for 14%, 10% and 9%, respectively, of the total amount of gallons we delivered. For the six month period ended June 30, 2011, sales in California and Arizona accounted for 56% and 10%, 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, reduce fuel consumption or reduce the availability of government grants, any of which could negatively affect our growth.

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

We loan to certain qualifying customers a portion of, and occasionally 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 consists of 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. Some of our customers, such as taxi owners, may depend on the CNG vehicles that we finance or lease to them as their sole source of income, which may make it difficult for us to recover the collateral in a bankruptcy proceeding. Any disruption in the credit markets may further reduce the amount of capital available to us and an economic recession or continued high unemployment rates may increase the rate of default by borrowers, leading to an increase in losses on our loan portfolio. As of June 30, 2011, we had $4.7 million outstanding in loans provided to customers to finance natural gas vehicle purchases.

Table of Contents

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 addition, any failure to comply with regulations related to the government procurement process at the federal, state or local level or restrictions on political activities and lobbying may result in administrative or financial penalties including being barred from providing services to governmental entities.

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

We may not be successful in developing or expanding our biomethane, or renewable natural gas, business.

In November 2010, we announced that we entered into an agreement to develop a pipeline quality biomethane project at a Republic Services owned landfill outside of Detroit, Michigan. We are also in the process of expanding our operations at our biomethane production facility at the McCommas Bluff landfill outside of Dallas, Texas. Biomethane production represents a new area of investment and operations for us, and we may not be successful in developing these projects and generating a financial return from our investment. Historically, projects that produce pipeline quality biomethane, or renewable natural gas, have often failed due to the volatile prices of conventional natural gas, unpredictable biomethane production levels and technological difficulties and costs associated with operating the production facilities. Our ability to succeed in expanding our McCommas Bluff project and developing our project in Michigan depends on our ability to successfully manage the construction and operation of biomethane production facilities and our ability to sell and market the biomethane at substantial premiums to recent conventional natural gas prices. If we are unsuccessful in managing the construction and operation of our biomethane production facilities, or if we are unable to sell and market biomethane at a premium to conventional natural gas prices, our business and financial results may be materially and adversely affected. Further, a proposal was recently submitted to the California Public Utilities Commission to classify as an unbundled renewable energy credit any in-state electricity generation using out-of-state biomethane. The adoption of this or similar proposals would likely impair our ability to obtain premium prices for biomethane. In the absence of state and federal programs that support premium prices for renewable natural gas, we will be unable to generate profit and financial return from these investments, and our financial results could be materially and adversely affected.

Operational issues, permitting and other factors at DCEMB’s landfill gas processing facility may adversely affect both DCEMB’s ability to supply biomethane and our operating results.

In August 2008, we acquired our 70% interest in DCE, which owns 100% of DCEMB. DCEMB is a party to a 15-year gas sale agreement with Shell Energy North America (US) L.P. (“Shell”) for the sale to Shell of specified levels of biomethane produced by DCEMB’s landfill gas processing facility. There is, however, no guarantee that DCEMB will be able to produce or sell up to the maximum volumes called for under the agreement or produce biomethane that meets the relevant pipeline specification. DCEMB’s ability to produce such volumes of biomethane depends on a number of factors beyond DCEMB’s control, including, but not limited to, the availability and composition of the landfill gas that is collected, successful permitting, the operation of the landfill by the City of Dallas and the reliability of the processing facility’s critical equipment. The DCEMB facility is subject to periods of reduced production or non-production due to upgrades, maintenance, repairs and other factors. For example, as part of an operational upgrade in March 2009, the facility was shut down for approximately one month. Also, on June 12, 2009, the facility was taken offline for repairs that were completed on July 2, 2009 and the facility was taken offline for upgrades from September 20, 2010 until September 25, 2010. Severe winter weather in Texas resulted in power outages and broken equipment in February 2011, resulting in a week of down time and an extended period during which the plant operated at half capacity. Future operational upgrades, including planned expansion of the plant, or complications in the operations of the facility could require additional shutdowns during 2011, and accordingly, DCEMB’s revenues may fluctuate from quarter to quarter.

Table of Contents

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 (income) were approximately $5.4 million, $3.2 million, $12.1 million, $23.7 million, $6.5 million, $6.4 million, $18.5 million, $1.9 million, $24.4 million, $(9.9) million, $1.8 million, $(13.8) million, $9.8 million and $5.6 million for the three months ended March 31, 2008, June 30, 2008, September 30, 2008, December 31, 2008, March 31, 2009, June 30, 2009, September 30, 2009, December 31, 2009, March 31, 2010, June 30, 2010, September 30, 2010, December 31, 2010, March 31, 2011 and June 30, 2011, respectively. Our quarterly results may fluctuate significantly as a result of a variety of factors, many of which are beyond our control. In particular, if our stock price increases or decreases in future periods during which our Series I warrants are outstanding, we will be required to recognize corresponding losses or gains related to the valuation of the Series I warrants that could materially impact our results of operations. 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 may be due to a number of 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, downtime at our facilities (including any shutdowns of DCEMB’s landfill gas processing facility), the amount and timing of operating costs, unanticipated expenses, capital expenditures related to the maintenance and expansion of our business, operations and infrastructure, our debt service obligations, 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, fluctuation in the value of our natural gas futures contracts, 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 future price of our common stock or the offering price of our common stock in future offerings could result in a reduction of the exercise price of our Series I warrants and result in dilution of our common stock.

We issued Series I warrants to purchase up to 3,314,394 shares of our common stock in connection with our registered direct offering completed in November 2008. 2,130,682 of the Series I warrants remain outstanding as of June 30, 2011. These warrants contain provisions that require an adjustment in the exercise price of the Series I warrants in the event that we price any offering of common stock at a price below the current exercise price, $12.68 per share, which, if we do, could result in a dilution of our common stock.

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

If our stockholders sell, or indicate an intention to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline. As of June 30, 2011, 70,317,747 shares of our common stock were outstanding. The 11,500,000 shares sold in our initial public offering, the 4,419,192 shares of common stock and the 2,130,682 shares of common stock subject to outstanding Series I warrants sold in our registered direct offering that closed on November 3, 2008, the 9,430,000 shares of our common stock sold in our common stock offering that closed on July 1, 2009 and the 3,450,000 shares of our common stock sold in our common stock offering that closed on November 11, 2010, are freely tradable without restriction or further registration under federal securities laws unless purchased by our affiliates.

In addition, upon the closing of our acquisition of IMW, we issued 4,017,408 shares of our common stock which are also registered for immediate resale. We issued an additional 601,926 shares to the IMW shareholder in January 2011. IMW’s shareholder had sold 3,408,468 shares of our common stock as of June 30, 2011.

Shares held by non-affiliates for more than six months may generally be sold without restriction, other than a current public information requirement, and may be sold freely without any restrictions after one year. All other outstanding shares of common stock may be sold under Rule 144 under the Securities Act, subject to applicable restrictions.

In addition, as of June 30, 2011, there were 10,802,152 shares underlying outstanding options and 17,130,682 shares underlying outstanding warrants (including the 2,130,682 Series I warrant shares sold in our registered direct offering which closed on November 3, 2008). All shares subject to outstanding options and warrants are eligible for sale in the public market to the extent permitted by the provisions of various option and warrant agreements and Rule 144, or have been registered under the Securities Act of 1933, as amended. 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.

Further, as of June 30, 2011, 16,539,720 shares of our stock held by our co-founder and board member T. Boone Pickens are subject to pledge agreements with banks. Should one or more of the banks be forced to sell the shares subject to the pledge, the trading price of our stock could also decline. In addition, a number of our directors and executive officers have entered into Rule 10b5-1 Sales Plans with a broker to sell shares of our common stock that they hold or that may be acquired upon the exercise of stock options. Sales

Table of Contents

under these plans will occur automatically without further action by the director or officer once the price and/or date parameters of the particular selling plan are achieved. As of June 30, 2011, 632,102 shares in the aggregate were subject to future sales by our named executive officers and directors under these selling plans. All sales of common stock under the plans will be reported through appropriate filings with the SEC.

A significant portion 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, 2011, T. Boone Pickens and affiliates (including Madeleine Pickens, his wife) owned in the aggregate 28% of our outstanding shares of common stock and beneficially owned in the aggregate approximately 41% of the outstanding shares of our common stock, inclusive of the 15,000,000 shares underlying a 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 have interests that differ from yours and may vote in a way with which you disagree and which may be adverse to your interests. This concentration of ownership may have the effect of delaying, preventing or deterring a change of control of our company, could deprive our stockholders of an opportunity to receive a premium for their stock as part of a sale of our company, and might ultimately affect the market price of our stock. Conversely, this concentration may facilitate a change in control at a time when you and other investors may prefer not to sell.

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

None.

Item 3.—Defaults upon Senior Securities

None.

Item 4.—(Removed and Reserved)

Item 5.—Other Information

None.

Table of Contents

Item 6.—Exhibits

(a) Exhibits

4.6	Form of Convertible Promissory Note. (Filed as Exhibit 4.6 to Form 8-K, as filed with the Securities and Exchange Commission on July 11, 2011, and incorporated herein by reference.)

10.57	First Amendment to the Warrant to Purchase Common Shares of Clean Energy Fuels Corp., dated June 6, 2011 (Filed as Exhibit 10.57 to Form 8-K, as filed with the Securities and Exchange Commission on June 6, 2011, and incorporated herein by reference.)

10.58	Loan Agreement, dated July 11, 2011, by and among Clean Energy Fuels Corp., Chesapeake NG Ventures Corporation and Chesapeake Energy Corporation. (Filed as Exhibit 10.58 to Form 8-K, as filed with the Securities and Exchange Commission on July 11, 2011, and incorporated herein by reference.)

10.59	Registration Rights Agreement, dated July 11, 2011, by and among Clean Energy Fuels Corp. and Chesapeake NG Ventures Corporation. (Filed as Exhibit 10.59 to Form 8-K, as filed with the Securities and Exchange Commission on July 11, 2011, and incorporated herein by reference.)

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.

101†	The following materials from the Company’s Quarterly Report of Form 10-Q for the quarter ended June 30, 2011, formatted in XBRL (eXtensible Business Reporting Language):

	(i)	Condensed Consolidated Balance Sheets at December 31, 2010 and June 30, 2011;
	(ii)	Condensed Consolidated Statement of Operations for the Three Months and Six Months Ended June 30, 2010 and 2011;
	(iii)	Condensed Consolidated Statements of Cash Flows for the Six Months ended June 30, 2010 and 2011; and
	(iv)	Notes to Condensed Consolidated Financial Statements, tagged as block of text.

Filed herewith.

†

Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

Table of Contents

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 8, 2011	By:	/s/ RICHARD R. WHEELER
		Richard R. Wheeler
		Chief Financial Officer (Principal financial officer and duly authorized to sign on behalf of the registrant)