UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~September 30, 2010~~March 31, 2011

Commission File Number: 001-33480

CLEAN ENERGY FUELS CORP.

(Exact name of registrant as specified in its charter)

Delaware ~~(State or other jurisdiction of~~ ~~incorporation)~~		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 o 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 filero		Accelerated filer x

Non-accelerated filer o		~~Smaller reporting company~~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 ~~November 2, 2010,~~May 4, 2011, there were ~~64,943,601~~70,303,645 shares of the registrant’s common stock, par value $0.0001 per share, issued and outstanding.

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

INDEX

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	1819
Item 3.—Quantitative and Qualitative Disclosures About Market Risk	31
Item 4.—Controls and Procedures	32
PART II.—OTHER INFORMATION
Item 1.—Legal Proceedings	32
Item 1A.—Risk Factors	3233
Item 2.—Unregistered Sales of Equity Securities and Use of Proceeds	4445
Item 3.—Defaults upon Senior Securities	4445
Item 4.—~~Submission of Matters to a Vote of Security Holders~~(Removed and Reserved)	4445
Item 5.—Other Information	4445
Item 6.—Exhibits	4445

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PART I.—FINANCIAL INFORMATION

Item 1.—Financial Statements (Unaudited)

Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Balance Sheets

December 31, ~~2009~~2010 and ~~September 30, 2010~~March 31, 2011 (Unaudited)

~~(Unaudited)~~(In thousands, except share data)

	December 31, 2009			September 30, 2010			December 31, 2010			March 31, 2011
Assets
Current assets:
Cash and cash equivalents	$	67,086,965		$	32,178,575		$	55,194		$	51,949
Restricted cash	2,500,000			2,500,000			2,500			4,893
Accounts receivable, net of allowance for doubtful accounts of $898,423 and $576,882 as of December 31, 2009 and September 30, 2010, respectively	16,339,730			32,339,929
Accounts receivable, net of allowance for doubtful accounts of $702 and $783 as of December 31, 2010 and March 31, 2011, respectively							45,645			32,318
Other receivables	8,862,213			11,061,428			27,280			16,194
Inventory, net	6,217,133			18,044,725			20,483			26,994
Prepaid expenses and other current assets	7,393,892			11,265,530			10,959			11,970
Total current assets	108,399,933			107,390,187			162,061			144,318
Land, property and equipment, net	172,182,436			199,968,904			211,643			217,384
Capital lease receivables	1,311,054			1,107,041
Notes receivable and other long-term assets	6,875,364			10,660,592			15,059			40,048
Investments in other entities	10,536,405			11,171,714			10,748			14,161
Goodwill	21,572,020			65,821,347			71,814			71,814
Intangible assets, net of accumulated amortization	34,921,361			112,926,564
Intangible assets, net							112,174			109,438
Total assets	$	355,798,573		$	509,046,349		$	583,499		$	597,163
Liabilities and Stockholders’ Equity
Current liabilities:
Current portion of long-term debt and capital lease obligations	$	2,439,263		$	29,328,727		$	22,712		$	23,166
Accounts payable	14,775,406			34,627,089			28,635			20,614
Accrued liabilities	9,695,443			20,390,637			28,137			29,012
Deferred revenue	2,691,007			12,006,967			17,507			12,466
Total current liabilities	29,601,119			96,353,420			96,991			85,258
Long-term debt and capital lease obligations, less current portion	9,781,425			33,175,323			41,704			64,492
Other long-term liabilities	36,039,864			38,203,504			28,588			28,979
Total liabilities	75,422,408			167,732,247			167,283			178,729
Commitments and contingencies
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 59,840,151 shares and 64,931,101 shares at December 31, 2009 and September 30, 2010, respectively	5,984			6,493
Common stock, $0.0001 par value. Authorized 149,000,000 shares; issued and outstanding 69,610,098 shares and 70,269,071 shares at December 31, 2010 and March 31, 2011, respectively							7			7
Additional paid-in capital	424,580,895			506,775,337			569,202			580,473
Accumulated deficit	(149,410,111		)	(165,711,509		)	(151,926		)	(161,678		)
Accumulated other comprehensive income (loss)	2,012,573			(2,915,569		)
Total stockholders’ equity of Clean Energy Fuels Corp.	277,189,341			338,154,752
Accumulated other comprehensive loss							(3,996		)	(3,991		)
Total Clean Energy Fuels Corp. stockholders’ equity							413,287			414,811
Noncontrolling interest in subsidiary	3,186,824			3,159,350			2,929			3,623
Total equity	280,376,165			341,314,102
Total liabilities and equity	$	355,798,573		$	509,046,349
Total stockholders’ equity							416,216			418,434
Total liabilities and stockholders’ equity							$	583,499		$	597,163

See accompanying notes to condensed consolidated financial statements.

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Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Statements of Operations

For the Three Months Ended March 31, 2010 and ~~Nine Months Ended~~

~~September 30, 2009 and 2010~~2011

(Unaudited)

Three Months Ended
September 30,

Nine Months Ended
September 30,

2009

2010

2009

2010

Revenue:

Product revenues

$
26,290,638

$
40,974,478

$
79,500,495

$
114,680,989

Service revenues

4,891,188

4,679,229

9,799,506

13,996,136

Total revenues

31,181,826

45,653,707

89,300,001

128,677,125

Operating expenses:

Cost of sales:

Product cost of sales

16,369,247

31,189,766

52,785,705

85,378,128

Service cost of sales

2,388,458

2,319,064

3,820,740

6,305,141

Selling, general and administrative

10,491,987

15,854,920

33,649,427

44,382,202

Depreciation and amortization

4,516,513

5,507,032

12,256,603

15,567,523

Derivative (gain) loss on Series I warrant valuation

15,422,310

(7,866,162
)
17,808,673

(5,876,855
)
Total operating expenses

49,188,515

47,004,620

120,321,148

145,756,139

Operating loss

(18,006,689
)
(1,350,913
)
(31,021,147
)
(17,079,014
)
Interest income (expense), net

(276,110
)
(70,126
)
(368,186
)
16,379

Other expense, net

(107,468
)
(308,346
)
(293,995
)
(303,769
)
Income from equity method investments

77,744

95,509

130,162

200,919

Loss before income taxes

(18,312,523
)
(1,633,876
)
(31,553,166
)
(17,165,485
)
Income tax benefit (expense)

(68,352
)
(290,121
)
(209,202
)
836,613

Net loss

(18,380,875
)
(1,923,997
)
(31,762,368
)
(16,328,872
)
Loss (income) attributable to noncontrolling interest

(79,708
)
94,123

430,972

27,474

Net loss attributable to Clean Energy Fuels Corp.

$
(18,460,583
)
$
(1,829,874
)
$
(31,331,396
)
$
(16,301,398
)
Loss per share attributable to Clean Energy Fuels Corp.

Basic

$
(0.31
)
$
(0.03
)
$
(0.59
)
$
(0.27
)
Diluted

$
(0.31
)
$
(0.03
)
$
(0.59
)
$
(0.27
)
Weighted average common shares outstanding

Basic

59,695,666

63,992,763

53,428,391

60,970,130

Diluted

59,695,666

63,992,763

53,428,391

60,970,130

(In thousands, except share and per share data)

	Three Months Ended March 31,
	2010			2011
Revenue:
Product revenues	$	34,273		$	58,532
Service revenues	4,716			6,809
Total revenues	38,989			65,341
Operating expenses:
Cost of sales:
Product cost of sales	25,496			43,850
Service cost of sales	2,063			3,154
Derivative (gains) losses:
Series I warrant valuation	18,605			3,300
Selling, general and administrative	13,649			18,030
Depreciation and amortization	4,991			7,210
Total operating expenses	64,804			75,544
Operating income (loss)	(25,815		)	(10,203		)
Interest income (expense), net	109			(820		)
Other income	43			601
Income from equity method investments	77			211
Loss before income taxes	(25,586		)	(10,211		)
Income tax (expense) benefit	1,203			735
Net loss	(24,383		)	(9,476		)
Income (loss) of noncontrolling interest	16			(277		)
Net loss attributable to Clean Energy Fuels Corp.	$	(24,367	)	$	(9,753	)
Loss per share attributable to Clean Energy Fuels Corp.:
Basic and diluted	$	(0.41	)	$	(0.14	)
Weighted-average common shares outstanding:
Basic and diluted	60,156,352			70,096,000

See accompanying notes to condensed consolidated financial statements.

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Clean Energy Fuels Corp.

Condensed Consolidated Statements of Cash Flows

For the ~~Nine~~Three Months Ended ~~September 30, 2009~~March 31, 2010 and ~~2010~~2011

(Unaudited)

Nine Months Ended
September 30,

2009

2010

Cash flows from operating activities:

Net loss

$
(31,762,368
)
$
(16,328,872
)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:

Depreciation and amortization

12,256,603

15,567,523

Provision for doubtful accounts

(1,074,005
)
138,777

Loss on disposal of assets

404,948

175,223

Stock option expense

10,572,136

9,221,647

Derivative (gain) loss on Series I warrant valuation

17,808,673

(5,876,855
)
Contingent consideration

—

—

Changes in operating assets and liabilities, net of assets and liabilities acquired:

Accounts and other receivables

(1,966,808
)
(6,073,435
)
Inventory

508,425

(3,433,927
)
Return of deposits on LNG trucks

5,672,424

255,124

Margin deposits on futures contracts

(3,155,771
)
(2,987,224
)
Capital lease receivables

790,442

1,142,835

Prepaid expenses and other assets

(1,199,224
)
(982,031
)
Accounts payable

1,095,378

13,588,186

Accrued expenses and other

444,996

7,388,381

Net cash provided by operating activities

10,395,849

11,795,352

Cash flows from investing activities:

Purchases of property and equipment

(25,419,519
)
(41,437,375
)
Proceeds from sale of property and equipment

51,140

280,556

Acquisition, net of cash acquired

(5,645,250
)
(15,585,377
)
Proceeds from sale of loans receivable

3,026,073

324,576

Investments in other entities

(4,203,758
)
(635,309
)
Net cash used in investing activities

(32,191,314
)
(57,052,929
)
Cash flows from financing activities:

Proceeds from issuance of long-term debt

7,159,570

—

Repayment of capital lease obligations and long-term debt

(2,724,257
)
(434,641
)
Proceeds from issuance of common stock and exercise of stock options

73,369,650

10,783,828

Net cash provided by financing activities

77,804,963

10,349,187

Net increase (decrease) in cash

56,009,498

(34,908,390
)
Cash, beginning of period

36,284,431

67,086,965

Cash, end of period

$
92,293,929

$
32,178,575

Supplemental disclosure of cash flow information:

Income taxes paid

$
59,227

$
219,144

Interest paid, net of approximately $509,363 and $295,000 capitalized, respectively

$
704,331

$
804,363

(In thousands)

	Three Months Ended March 31,
	2010			2011
Cash flows from operating activities:
Net loss	$	(24,383	)	$	(9,476	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization	4,991			7,210
Asset impairments	—			45
Provision for doubtful accounts and notes receivables	75			79
Gain on disposal of assets	(43		)	—
Derivative loss	18,605			3,300
Stock-based compensation expense	3,040			3,377
Accretion of notes payable	—			720
Loss (gain) on contingent consideration for acquisitions	300			(696		)
Changes in operating assets and liabilities, net of assets and liabilities acquired:
Accounts and other receivables	(2,678		)	24,388
Inventory	(1,205		)	(6,511		)
Margin deposits on futures contracts	(2,560		)	1,760
Prepaid expenses and other assets	1,051			(1,379		)
Accounts payable	(1,392		)	(8,021		)
Accrued expenses and other	3,232			(4,899		)
Net cash provided by (used in) operating activities	(967		)	9,897
Cash flows from investing activities:
Purchases of property and equipment	(8,798		)	(10,816		)
Proceeds from sale of property and equipment	73			—
Restricted cash related to DCEMB bond offering	—			(27,061		)
Investments in other entities	(77		)	(2,700		)
Net cash used in investing activities	(8,802		)	(40,577		)
Cash flows from financing activities:
Proceeds from issuance of common stock and exercise of stock options	9,240			394
Proceeds from capital lease obligations and debt instruments	—			41,548
Proceeds from revolving line of credit	—			10,240
Proceeds from minority interest DCE equity contribution	—			417
Payments for debt issuance costs	—			(1,767		)
Repayment of borrowing under revolving line of credit	—			(7,340		)
Repayment of capital lease obligations and debt instruments	(243		)	(15,199		)
Net cash provided by financing activities	8,997			28,293
Effect of exchange rates on cash and cash equivalents	—			(858		)
Net decrease in cash	(772		)	(3,245		)
Cash, beginning of period	67,087			55,194
Cash, end of period	$	66,315		$	51,949
Supplemental disclosure of cash flow information:
Income taxes paid	$	157		$	597
Interest paid, net of approximately $98 and $118 capitalized, respectively	94			131

See accompanying notes to condensed consolidated financial statements.

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~~CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES~~Clean Energy Fuels Corp. and Subsidiaries

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~Notes to Condensed Consolidated Financial Statements

(Unaudited)

(In thousands, except share data)

Note 1—General

Nature of Business: Clean Energy Fuels Corp. ~~(the~~, 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~~States. Beginning September 7, 2010 with its acquisition of I.M.W. Industries, Ltd. (“IMW”), the Company began selling certain equipment and ~~Canada.~~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 ~~211~~238 natural gas fueling locations in Arizona, California, Colorado, ~~District of Columbia,~~ 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 ~~subsidiaries~~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 owns a facility that ~~are dedicated to~~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 ~~advanced~~of natural gas fueling compressors and related ~~equipment, processing~~equipment. On December 15, 2010, the Company acquired 100% of Wyoming Northstar Incorporated, Southstar, LLC, and ~~selling renewable biomethane~~M&S Rental LLC (collectively “Northstar”), a provider of design, engineering, construction and ~~providing~~maintenance services for liquefied natural gas ~~vehicle conversions. All of the Company’s revenues are presented net of taxes collected.~~(“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 nine~~ months ended ~~September 30, 2009~~March 31, 2010 and ~~2010.~~2011. All intercompany accounts and transactions have been eliminated in consolidation. The three ~~and nine~~ month periods ended ~~September 30, 2009~~March 31, 2010 and ~~2010~~2011 are not necessarily indicative of the results to be expected for the year ending December 31, ~~2010~~2011 or for any other interim period or for any future year.

Certain information and disclosures normally included in the notes to consolidated financial statements have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (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, ~~2009~~2010 that are included in the Company’s Annual Report on Form 10-K filed with the SEC on March 10, ~~2010.~~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

Operating and Maintenance Contracts

In May and June 2009, the Company acquired four compressed natural gas operations and maintenance services contracts for ~~$5.6 million~~$5,645 in cash. The Company recorded ~~$0.5 million~~$537 to tangible assets and ~~$5.1 million~~$5,108 of intangible assets related to customer relationships, which are being amortized over their expected lives of eight years. The results of operations of the

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acquired contracts are included in the Company’s consolidated financial statements from their acquisition dates forward, which are May 2009 for two of the contracts and June 2009 for the remaining two contracts. In addition, as part of the acquisition, the Company became the custodian of certain customer-owned inventories that it is required to replenish when the contracts expire. The customer-owned inventory was valued onby the ~~Company’s books~~Company as an asset at ~~$986,000~~$986 with a corresponding balance of ~~$986,000~~$986 recorded as a liability on the acquisition dates of the contracts. During the fourth quarter of 2010, the Company recorded a charge of $1,531 related to the impairment of an intangible asset originally recorded with this acquisition.

Vehicle Conversion

On October 1, 2009, the Company purchased all the outstanding shares of BAF, ~~Technologies, Inc. (“BAF”),~~ under a stock purchase agreement. The Company paid an aggregate of ~~$8.5 million~~$8,467 to acquire BAF. Pursuant to the terms of the agreement, the purchase price was reduced by the amount of BAF’s outstanding debt, which was repaid in full at closing. Due to the fact that approximately ~~$3.8 million~~$3,790 of BAF’s outstanding debt, including interest, was held by a subsidiary of the Company, the Company paid a net amount of approximately ~~$4.7 million~~$4,717 in cash to acquire BAF at the closing. The former BAF shareholders ~~will be able~~are also eligible to ~~earn~~receive additional consideration ifbased on BAF ~~achieves~~achieving certain gross profit targets in ~~fiscal~~ 2010 and 2011. The additional consideration ~~will be~~is determined as a percentage of gross profit based on a sliding scale that increases at certain gross profit levels, subject to achieving a minimum gross profit target and capped by a maximum additional payment amount. For 2010, the shareholders of BAF will receive between one and twenty-six percent of the gross profit of BAF as additional consideration if BAF achieves $8 million or more in gross profit, up to a maximum of $11 millionCompany accrued approximately $2,080 in additional consideration ~~(which maximum amount would be~~ payable ifto the former BAF ~~achieved approximately $42.3 million in gross profit in 2010).~~

~~Table~~shareholders as a result of ~~Contents~~

BAF’s performance during the year. For 2011, the former shareholders of BAF will receive between one and twenty-one percent of the gross profit of BAF as additional consideration if BAF achieves ~~$8.5 million~~$8,500 or more in gross profit, up to a maximum of ~~$11 million~~$11,000 in additional consideration (which maximum amount would be payable if BAF achieved approximately ~~$52.4 million~~$52,400 in gross profit in 2011).

The Company accounted for this acquisition in accordance with Financial Accounting Standards Board (“FASB”) authoritative guidance for business combinations, which requires the Company to recognize the assets acquired and the liabilities assumed ~~and any non-controlling interest in the acquiree~~ at the acquisition date ~~measured~~ at their fair values as of that 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	$	4,820,188		$	4,820
Property, plant and equipment	157,624			158
Identifiable intangible assets	10,660,000			10,660
Goodwill	774,142			774
Total assets acquired	16,411,954			16,412
Current liabilities assumed	(4,844,672		)	(4,845		)
Total purchase price	$	11,567,282		$	11,567

~~Management~~The Company allocated approximately ~~$10.7 million~~$10,660 of the purchase price to the identifiable intangible assets related to customer relationships, engine certifications 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 of 1.5 to 8 years. In addition, ~~management~~the Company allocated ~~$0.8 million~~$774 to goodwill as part of the acquisition and recorded a contingent liability of ~~$3.1 million~~$3,100 related to the possible consideration owed to BAF shareholders if BAF achieves certain gross profit targets in 2010 and 2011. Under the accounting guidance the Company must follow for this acquisition, 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 ~~charge of $0.3 million and $0.2 million during the quarters ended March 31, 2010 and June 30, 2010, respectively, and a~~ gain of ~~$0.5~~$0.1 million during the quarter ended ~~September 30, 2010 related~~March 31, 2011, compared to ~~this obligation.~~a loss of $0.3 million during the quarter ended March 31, 2010. These amounts are recorded in selling, general and administrative expenses in the accompanying condensed consolidated ~~statement~~statements of operations. ~~The~~At March 31, 2011, the fair value of the ~~obligation will increase or decrease in relation to any increase or decrease in the anticipated gross profit of BAF.~~contingent consideration was approximately $3,000.

The results of BAF’s operations have been included in the Company’s consolidated financial statements since October 1, 2009.

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 ~~(the “IMW Acquired Business”)~~ of ~~I.M.W. Industries Ltd., a British Columbia corporation (“IMW”). The~~IMW. IMW ~~Acquired Business~~ manufactures and services advanced, non-lubricated natural gas fueling compressors and related equipment for the global natural gas fueling market. ~~The~~ IMW ~~Acquired Business~~ is headquartered near Vancouver, British Columbia, has a second manufacturing facility near Shanghai, China and has other sales and service offices in Bangladesh, Colombia and the United States.

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In connection with the closing of the Company’s acquisition of ~~the~~ IMW, ~~Acquired Business,~~ a subsidiary of the Company (the “Acquisition Subsidiary”) paid an upfront cash payment of approximately ~~$15.6 million (subject to a final working capital adjustment)~~$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 ~~$288,000 will be~~$288 was paid by the Acquisition Subsidiary ~~once~~when the Chinese regulatory authorities ~~approve~~subsequently approved the transfer of IMW Compressors (Shanghai) Co. Ltd. to the Acquisition ~~Subsidiary, which is anticipated within the next thirty days.~~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 ~~$12,500,000~~$12,500 that ~~is due and payable~~was paid on January 31, 2011, (ii) a promissory note with a principal amount of ~~$12,500,000~~$12,500 that is due and payable on January 31, 2012, (iii) a promissory note with a principal amount of ~~$12,500,000~~$12,500 that is due and payable on January 31, 2013, and (iv) a promissory note with a principal amount of ~~$12,500,000~~$12,500 that is due and payable on January 31, 2014. Each payment under the IMW Notes will consist of ~~$5.0 million~~$5,000 in cash and ~~$7.5 million~~$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 ~~Acquisition Subsidiary’s~~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 ~~Acquired Business.~~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 ~~the~~ IMW ~~Acquired Business~~ 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 0zero and ~~23 percent~~23% of the gross profit of ~~the~~ IMW ~~Acquired Business~~ as additional consideration, up to a maximum of ~~$40.0 million~~$40,000 in the aggregate (which maximum would be payable if ~~the~~ IMW ~~Acquired Business~~ achieves approximately ~~$174.0 million~~$174,000 in gross profit over the four-year period during which these earn-out payments may be made).

~~Table of Contents~~

Current assets	$	25,948,510		$	27,149
Property, plant and equipment	2,558,791			2,559
Identifiable intangible assets	81,400,000			81,400
Goodwill	44,249,327			45,049
Total assets acquired	154,156,628			156,157
Liabilities assumed	(23,985,870		)	(25,986		)
Total purchase price	$	130,170,758		$	130,171

Management allocated approximately ~~$81.4 million~~$81,400 of the purchase price to the 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 ~~$44.2 million~~$45,049 to goodwill as part of the acquisition and recorded a contingent liability of ~~$9.3 million~~$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 approximately $617 during the quarter ended March 31, 2011. This amount is recorded in selling, general and administrative expenses in the accompanying condensed consolidated statement of operations. At March 31, 2011, the fair value of the contingent consideration was $7,483.

As of ~~November 8, 2010,~~May 9, 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 ~~retrospectively.~~retroactively. The final purchase price allocation is pending ~~the receipt of valuation work, the Company’s internal review of such work, as well as~~ the consideration of income tax related matters.

Under the accounting guidance the Company must follow for this acquisition, 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 value of the obligation will increase or decrease in relation to any increase or decrease in the anticipated gross profit of the IMW Acquired Business. The Company determined that no adjustment was necessary to the original amount recorded at September 30, 2010. Any future adjustments will be included in selling, general and administrative expenses in the accompanying condensed consolidated statement of operations.

~~The difference between the fair value and the face value of the future payments will be accreted to interest expense using the effective interest method over the life of the payments.~~

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

Table of Contents

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.

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 ~~presents~~summarizes the ~~Company’s unaudited pro forma results of operations for the three and nine months ended September 30, 2009 and 2010 as if the acquisition had occurred at the beginning~~estimated fair values of the ~~respective periods. The pro forma financial data for all periods presented include adjustments for~~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 ~~following: (i) elimination of intercompany transactions (ii) recording the additional amortization expense from~~purchase price to the identifiable intangible assets, ~~(iii) adjusting the~~$2,250 of which is related to non-compete agreements, customer relationships, and backlog. The fair value of these identifiable intangibles will be amortized on a straight-line basis over their estimated ~~tax provision~~useful lives ranging from one to ten years. The Company also allocated $1,100 of the ~~pro forma combined results; (iv) United States Generally Accepted Accounting Principles conversion adjustments and (v) the issuance of the Company’s common stock~~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 Company prepared the pro forma financial information for the combined entities for comparative purposes only, and it is not indicative of what actual results would have been if the acquisition had taken place at the beginning of the respective periods, or of future results.

For the Three Months Ended
September 30,

For the Nine Months Ended
September 30,

(in thousands, except per share data)

2009

2010

2009

2010

Revenue

$
40,705

$
58,372

$
113,988

$
166,192

Net loss

(20,818
)
(3,515
)
(38,176
)
(23,115
)
Loss per share

Basic

(0.33
)
(0.05
)
(0.66
)
(0.38
)
Diluted

(0.33
)
(0.05
)
(0.66
)
(0.38
)

~~For~~As of May 9, 2011, the ~~period from September 7, 2010 through September 30, 2010,~~purchase price allocation is preliminary and could change materially in subsequent periods. Any subsequent changes to the ~~IMW Acquired Business contributed approximately $3.3 million and $(0.3) million, respectively,~~purchase price allocation that result in material changes to the Company’s ~~revenues and net loss for~~consolidated financial results will be adjusted retroactively. The final purchase price allocation is pending the ~~period.~~consideration of income tax related matters.

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—~~Natural Gas~~ Derivative ~~Financial Instruments~~Transactions

The Company, in an effort to manage its natural gas commodity price risk exposures related to certain contracts, utilizes derivative financial instruments. The Company, from time to time, enters into natural gas futures contracts that are over-the-counter swap transactions that convert its index-based gas supply arrangements to fixed-price arrangements. The Company accounts for its derivative instruments in accordance with authoritative guidance for derivative instruments and hedging activities, which requires the recognition of all derivatives as either assets or liabilities in the condensed consolidated balance sheet and the measurement of those instruments at fair value. Historically, through September 30, 2008, the Company’s derivative instruments have not qualified for hedge accounting under the authoritative guidance. On and after July 1, 2008, the Company entered into futures contracts that did qualify for hedge accounting. The Company’s futures contracts at September 30, 2009 and 2010 are being accounted for as cash flow hedges under the authoritative guidance and are being used to mitigate the Company’s exposure to changes in the price of natural gas and not for speculative purposes. At September 30, 2009 and 2010, all of the Company’s futures contracts qualified for hedge accounting.

~~Table of Contents~~

The counter-party to the Company’s derivative transactions is a high credit quality counterparty; however, the Company is subject to counterparty credit risk to the extent the counterparty to the derivatives is unable to meet its settlement commitments. The Company manages this credit risk by minimizing the number and size of its derivative contracts. The Company actively monitors the creditworthiness of its counterparties and records valuation adjustments against the derivative assets to reflect counterparty risk, if necessary. The counter-party is also exposed to credit risk of the Company, which requires the Company to provide cash deposits as collateral.

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 ~~the~~FASB authoritative guidance. The Company recorded an unrealized ~~gains~~(gains) losses of ~~approximately $1.5 million,~~$3,865 and ~~an unrealized loss of approximately $5.1 million,~~$(708), in ~~accumulated~~ other comprehensive income (loss) for the three month periods ended March 31, 2010 and 2011, respectively, related to its futures ~~contracts for the nine month periods ended September 30, 2009 and 2010, respectively.~~contracts. Of the ~~approximately $5.0 million~~$3,363 liability for the Company’s ~~futures~~future contracts at ~~September 30, 2010, approximately $3.3 million~~March 31, 2011, $2,851 is included in accrued liabilities for the short-term amount, and ~~approximately $1.7 million~~$512 is included in other long-term liabilities for the long-term amount in the Company’s consolidated balance sheet as of March 31, 2011. Of the $3,706 liability for the Company’s futures contracts at March 31, 2010, $1,913 is included in accrued liabilities for the short-term amount, and $1,793 is included in other long-term liabilities for the long-term amount in the Company’s condensed consolidated balance sheet ~~at September 30,~~as of March 31, 2010. Of the asset for the Company’s futures contracts of approximately $0.8 million at September 30, 2009, approximately $0.5 million is included in prepaid expenses and other current assets for the short-term amount, and approximately $0.3 million is included in other long-term assets for the long-term amount in the Company’s condensed consolidated balance sheet at September 30, 2009. The Company’s ineffectiveness related to its futures contracts during the ~~nine~~three month periods ended ~~September 30, 2009~~March 31, 2010 and ~~2010, respectively, was~~2011 were insignificant. For the ~~nine month periods~~three months ended ~~September 30, 2009~~March 31, 2010 and ~~2010,~~2011, the Company recognized a ~~loss~~gain of approximately ~~$1.7 million~~$213 and a loss of approximately ~~$0.9 million,~~$751, respectively, in cost of sales in the accompanying condensed consolidated ~~statements~~statement of operations related to its futures contracts that were settled during the respective ~~nine-month~~ periods.

~~The Company is required to make certain deposits on its futures contracts, should any exist. At September 30, 2009, the Company had $3.9 million~~9

Table of margin deposits related to its futures contracts covering approximately 31.8 million gasoline gallon equivalents of natural gas fuel, of which $2.6 million related to contracts that expired during the following twelve months and were classified as current at September 30, 2009. At September 30, 2010, the Company had $5.9 million of margin deposits related to its futures contracts covering approximately 19.9 million gasoline gallon equivalents of fuel, of which $3.8 million were current at September 30, 2010. The current portion of the deposits are recorded in prepaid expenses and other current assets, and the long-term portion of the deposits are recorded in notes receivable and other long-term assets in the Company’s condensed consolidated balance sheets.Contents

The following table presents the notional amounts and ~~weighted average~~weighted-average fixed prices per gasoline gallon equivalent of the Company’s natural gas futures contracts as of ~~September 30, 2010:~~March 31, 2011:

Gallons

Weighted
Average Price
Per Gasoline
Gallon
Equivalent

October to December, 2010

2,880,000

$
0.77

2011

11,600,000

0.82

2012

5,160,000

0.81

January to May, 2013

300,000

0.81

~~Table of Contents~~

	Gallons	Weighted Average Price Per Gasoline Gallon Equivalent
April to December, 2011	8,800,000	$	0.82
2012	5,160,000	$	0.81
January to May, 2013	300,000	$	0.81

Note 5—Other Receivables

Other receivables at December 31, ~~2009~~2010 and ~~September 30, 2010~~March 31, 2011 consisted of the following:

	December 31, 2009		September 30, 2010		December 31, 2010		March 31, 2011
Loans to customers to finance vehicle purchases	$	1,179,356	$	1,421,327	$	1,013	$	990
Capital lease receivables	1,209,819		270,997		273		266
Accrued customer billings	—		4,548,657		1,976		5,306
Advances to vehicle manufacturers	2,413,066		1,943,696		3,603		3,444
Fuel tax credits	2,626,551		660,034
Fuel tax and carbon credits					17,577		3,709
Other	1,433,421		2,216,717		2,838		2,479
	$	8,862,213	$	11,061,428	$	27,280	$	16,194

Note 6—~~Inventories:~~Inventories

Inventories ~~at December 31, 2009 and September 30, 2010 consisted of the following:~~

December 31,
2009

September 30,
2010

Raw materials and spare parts

$
6,217,133

$
15,266,724

Work in progress

—

845,514

Finished goods

—

1,932,487

$
6,217,133

$
18,044,725

~~Raw materials and spare parts~~ are stated at the lower of cost ~~which is direct material and freight, and net realizable value,~~or market on a first-in, first-out basis. ~~Work in progress~~Management’s estimate of market includes a provision for slow-moving or obsolete inventory based upon inventory on hand and ~~finished goods inventory is recorded at~~forecasted demand.

Inventories consisted of the ~~lower~~following as of ~~cost, which includes the direct cost of materials plus freight, labor~~December 31, 2010 and ~~overhead, and net realizable value.~~March 31, 2011:

	December 31, 2010		March 31, 2011
Raw materials and spare parts	$	17,634	$	24,079
Work in process	1,196		1,055
Finished goods	1,653		1,860
Total	$	20,483	$	26,994

Note 7—Land, Property and Equipment

Land, property and equipment at December 31, ~~2009~~2010 and ~~September 30, 2010~~March 31, 2011 are summarized as follows:

	December 31, 2009			September 30, 2010			December 31, 2010			March 31, 2011
Land	$	472,616		$	472,616		$	1,198		$	1,198
LNG liquefaction plants	91,830,640			92,399,792			92,856			92,924
Station equipment	83,935,092			90,752,634			91,492			98,278
LNG tanker trailers	11,887,326			11,904,446
Biomethane plant	6,502,854			15,991,918
LNG trailers							12,020			12,020
Other equipment	9,241,630			13,454,432			24,478			26,940
Construction in progress	14,190,917			31,898,892			53,386			54,125
	218,061,075			256,874,730			275,430			285,485
Less accumulated depreciation	(45,878,639		)	(56,905,826		)
Less: accumulated depreciation							(63,787		)	(68,101		)
	$	172,182,436		$	199,968,904		$	211,643		$	217,384

Table of Contents

Note 8—Investments in Other Entities

Through ~~September 30, 2010,~~March 31, 2011, the Company has invested approximately ~~$10.4 million~~$12,003 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 has now met its investment commitment to VPG and will not be required to invest additional funds under its original investment commitment.~~ 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.

Note 9—Accrued Liabilities

Accrued liabilities at December 31, ~~2009~~2010 and ~~September 30, 2010~~March 31, 2011 consisted of the following:

December 31,
2009

September 30,
2010

Salaries and wages

$
2,555,849

$
3,616,035

Accrued gas purchases

627,710

1,207,235

Obligation under derivative liability

—

3,263,041

Contingent obligations

—

3,762,000

Accrued property and other taxes

2,383,707

2,448,350

Accrued professional fees

577,470

798,765

Accrued employee benefits

777,058

1,577,280

Accrued warranty liability

1,135,846

1,992,667

Other

1,637,803

1,725,264

$
9,695,443

$
20,390,637

~~Table of Contents~~

	December 31, 2010		March 31, 2011
Salaries and wages	$	2,218	$	1,844
Accrued gas and equipment purchases	6,995		9,968
Derivative liability	3,060		2,851
Accrued refund of tax credits	880		309
Contingent consideration obligations	3,493		3,299
Accrued property and other taxes	3,999		2,039
Accrued professional fees	670		620
Accrued employee benefits	1,659		1,497
Accrued warranty liability	2,338		2,483
Other	2,825		4,102
	$	28,137	$	29,012

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 ~~which are included in current liabilities for the short-term portion, and in other long-term liabilities for the long-term portion on the Company’s condensed consolidated balance sheets,~~ are presented in the following tables:

	December 31, 2009			September 30, 2010			March 31, 2010			March 31, 2011
Warranty liability at beginning of year	$	—		$	1,135,846		$	1,136		$	2,338
Acquired liability	989,112			741,299
Assumed liability through acquisitions							—			—
Costs accrued for new warranty contracts and changes in estimates for pre-existing warranties	221,410			478,219			253			405
Service obligations honored	(74,676		)	(362,697		)	(58		)	(260		)
Warranty liability at end of year	$	1,135,846		$	1,992,667
Current portion	726,356			927,930
Non-current portion	409,490			1,064,737
Warranty liability at end of period	$	1,135,846		$	1,992,667		$	1,331		$	2,483

Note 11—Long-term Debt

December 31,
2009

September 30,
2010

Facility B loan

$
10,047,492

$
9,908,978

IMW promissory notes

—

43,500,000

IMW assumed debt

—

7,064,774

Capital lease obligations

2,173,196

2,030,298

Total debt & capital lease obligations

12,220,688

62,504,050

Less amounts due within one year and short-term borrowings

(2,439,263
)
(29,328,727
)
Total long-term debt & capital lease obligations

$
9,781,425

$
33,175,323

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~~Agreement”) with PlainsCapital Bank (“PCB”). The Company borrowed ~~$18.0 million~~$18,000 (the “Facility A Loan”) to finance the acquisition of its membership interests in DCE. The Company also obtained a ~~$12.0 million~~$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 ~~$20.0 million~~$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.~~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 addition of an unused facility fee, as well as~~ 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%) ~~times~~of the unused portion. As of ~~September 30, 2010,~~March 31, 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 ~~$2,800,000.~~$2,800. Pursuant to an amendment to the Facility B loan between the Company and PCB dated November 1, 2010, ~~for a nominal fee,~~ PCB agreed to forgo the scheduled payment due from the Company on August 1, 2010 in the amount of ~~$2.0 million~~$2,059 until January 31, ~~2011. As of September 30, 2010,~~2011, which payment was made on such date. On March 31, 2011, the Company ~~had an outstanding balance of $9.9 million~~paid in full the remaining principal and interest that was due under the Facility B Loan. ~~Any amount~~

Table of ~~unpaid principal and interest outstanding on the Facility B Loan is due and payable on August 15, 2013.~~Contents

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 ~~$300,000~~$300 in August 2008 in connection with the Credit Agreement. As of ~~September 30, 2010,~~March 31, 2011, the unamortized balance of the facility fee was ~~$172,500.~~$86. 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 ~~$6.0 million,~~$6,000, accounts receivable balances, as defined, of not less than ~~$8.0 million,~~$8,000, consolidated net worth, as defined, of not less than ~~$150.0 million,~~$150,000, and a debt to equity ratio, as defined, of not more than 0.3 to 1.1.0. Beginning in the quarter ended June 30, 2009, the Company must also maintain a ~~specific~~ 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 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 and the Facility B Loan.~~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 ~~$8.0 million~~$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 is required to maintain a debt service ratio, as defined, of not less than 1.5 to 1. For the quarter ended September 30, 2010, the Company was not in compliance with this covenant; however, PCB agreed by letter dated November 1, 2010 to waive compliance with the covenant until the next quarterly calculation at December 31, 2010. The entire amount of the Facility B Loan is shown as current in the accompanying condensed consolidated balance sheets based on the prevailing ~~accounting guidance.~~1.0. To the extent the Company’s operating results do not materialize as ~~anticipated,~~planned, the Company could violate this covenant ~~again~~ in the future. ~~In the event~~As of March 31, 2011, the Company ~~violates any of the covenants~~was in ~~the future it would seek another waiver from PCB.~~compliance with its covenants. The Credit Agreement is secured by the Company’s interest in ~~and note receivable from,~~ DCE, ~~(described below),~~ 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 ~~$57.4 million~~$45,932 at ~~September 30, 2010.~~March 31, 2011. The Company maintains ~~$2.5 million~~$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 or the Facility B Loan.~~Credit. Such amount is included as restricted cash in the Company’s condensed consolidated balance sheet at ~~September 30, 2010.~~March 31, 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 ~~$14.0 million~~$14,000 to DCE for future capital expenditures or other uses as agreed to by the Company, in its sole discretion. As of September 30, 2010, the Company is owed approximately $10.6 million under the DCE Loan. Interest on the unpaid balance accrues at a rate of 12% per annum and became payable quarterly beginning on September 30, 2008. The principal amount of the loan is due and payable in annual payments commencing on August 1, 2009, and continuing each anniversary date thereafter, with each such payment being in an amount equal to the lesser of the aggregate principal amount of the DCE Loan then outstanding or $2,800,000. As referenced above, PCB agreed to forgo the Company’s next Facility B Loan payment in the amount of $2.0 million until JanuaryOn March 31, ~~2011. The Company granted the same extension to DCE for its next payment on the DCE Loan. On August 1, 2013,~~2011, the entire amount of unpaid principal and interest due under the DCE Loan ~~is due and payable.~~

was paid to the Company. The ~~principal and accrued interest balances, as well as any~~ interest income related to the DCE Loan ~~are~~was eliminated in the accompanying condensed consolidated ~~financial~~ 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. ~~Any event~~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 ~~default~~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 onLoan. The Company, in turn, used the proceeds from the payoff of the DCE Loan ~~results in a cross-default of~~to repay approximately $8,000 owed by the ~~Company’s Credit Agreement with PCB. Events of default include failure~~Company to ~~make payments when due, DCE’s failure to perform~~PCB under the ~~provisions of its landfill lease with the City of Dallas, DCE’s violation of a covenant under its operating agreement and other standard events of default.~~Facility B Loan on March 31, 2011.

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Pursuant to the Loan Agreement, dated as of January 1, 2011 (the “Loan Agreement”), between the Company’s 70% owned subsidiary 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 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.

Pursuant to a Consent and Agreement, by and between Shell Energy, The Bank of New York Mellon Trust Company, N.A., as Depository Bank, DCEMB and the Trustee (the “Depository Bank”), 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, 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 March 31, 2011, $24,668 was included in long term assets 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 March 31, 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 ~~IMW Acquired Business, the Acquisition Subsidiary~~Company issued the IMW Notes ~~(as described in~~(see note ~~2 herein) to IMW.~~2).

Also in connection with the closing of the Company’s acquisition of IMW, the ~~IMW Acquired Business, the Acquisition Subsidiary~~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 ~~Acquisition Subsidiary~~Company assumed the obligations and liabilities of IMW under the following arrangements, as amended, with HSBC (collectively, the “IMW Lines of Credit”):

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(i) An operating line of credit with a limit of ~~$7,750,000~~$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 ~~the Acquisition Subsidiary.~~IMW.

(ii) A bank guarantee line with a limit of CAD$~~3,000,000,~~3,000, which allows ~~the Acquisition Subsidiary~~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$~~13,750,000.~~13,750. The forward exchange contract line allows ~~the Acquisition Subsidiary~~IMW to enter into foreign exchange forward contracts up to the notional limit of CAD$~~13,750,000~~13,750 (no forward exchange contracts were outstanding at ~~September 30, 2010)~~March 31, 2011).

(iv) A MasterCard limit with a maximum amount of CAD$~~150,000.~~150.

(v) An operating line ~~of credit~~ with a limit of ~~4,000,000~~5,000 Renminbi (“RMB”) (CAD$~~593,000)~~743) 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 sub-limit lines cannot exceed 5,000 RMB.

(vi) A ~~bank guarantee line with a limit of 1,000,000 RMB (CAD$148,000).~~

~~(vii)A 16,750,000~~16,750 Bengali Taka (CAD$~~239,000)~~239) operating line of credit bearing interest at 14%.

~~(viii)~~(vii) A ~~320,000,000~~170,000 Columbian Peso (CAD$~~166,000)~~88) operating line of credit bearing interest at the Colombia benchmark rate plus 7 to 9%.

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 ~~the Acquisition Subsidiary,~~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, we have 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 ~~the Acquisition Subsidiary~~IMW shall not permit: 1) its ratio of debt to tangible net worth to be greater than 3.25 to 11.0 until December 31, 2010 and greater than ~~3.00~~4.0 to ~~1 from~~1.0 on or after January 1, 2011 ~~onward,~~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$~~3,000,000~~3,000 and 3) its ratio of current assets to current liabilities to be less than 1.15 to 11.0 until December 31, 2010 and less than 1.25 to ~~1 from~~1.0 on or after January 1, ~~2011 onward.~~2011. IMW iswas in compliance with the financial covenants as of September 30, 2010. Further, (i) 0884808 B.C. Ltd., a British Columbia corporation and a subsidiary of the Company (“Canadian AcqCo”), guaranteed the Acquisition Subsidiary’s obligations under the IMW Lines of Credit, (ii) Canadian AcqCo entered into a general security agreement with HSBC pursuant to which Canadian AcqCo agreed that the IMW Lines of Credit are secured by a first priority security interest in all of its present and after acquired personal property, and (iii) Clean Energy, a California corporation and a subsidiary of the Company (“CE”), agreed to inject not less than USD$2,000,000 of additional working capital into the Acquisition Subsidiary at the closing of the Company’s acquisition of the IMW Acquired Business.March 31, 2011.

In addition, CEthe Company and ~~Canadian AcqCo~~IMW agreed that should the making of any scheduled payment by IMW to the ~~Acquisition Subsidiary to~~seller of IMW under the IMW Notes result in ~~the Acquisition Subsidiary~~IMW being in breach of the Assumption Agreement, the IMW Lines of Credit or the Security, ~~CE and Canadian AcqCo~~the Company shall furnish ~~the Acquisition Subsidiary~~IMW with the funds needed to remain in compliance with the Assumption Agreement, the IMW Lines of Credit and the Security. Further, CEthe Company and ~~Canadian AcqCo~~IMW agreed that should ~~the Acquisition Subsidiary~~IMW make any future earn-out payments to the seller of IMW ~~shareholder~~ in connection with the acquisition of ~~the~~ IMW, ~~Acquired Business,~~ and should the making of such earn-out payments result in ~~the Acquisition Subsidiary~~IMW being in breach of the Assumption Agreement, the IMW Lines of Credit or the Security, then ~~CE and Canadian AcqCo~~the Company shall furnish ~~the Acquisition Subsidiary~~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 notes at March 31, 2011 was $2,946. The difference between the carrying amount and the face amount will be accreted to interest expense over the remaining term of the notes.

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

	December 31, 2010			March 31, 2011
Facility B loan	$	9,909		$	—
IMW future payment notes	44,568			33,366
Northstar future payments	2,900			2,946
DCE notes	435			585
DCEMB notes	—			40,200
IMW assumed debt	4,626			7,669
Capital lease obligations	1,978			2,892
Total debt and capital lease obligations	64,416			87,659
Less amounts due within one year and short-term borrowings	(22,712		)	(23,166		)
Total long-term debt and capital lease obligations	$	41,704		$	64,492

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Note 12—Earnings Per Share

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

Three Months Ended
September 30,

Nine Months Ended
September 30,

Three Months Ended
March 31,

2009

2010

2009

2010

2011

Basic and diluted:

Weighted average number of common shares outstanding

59,695,666

63,992,763

53,428,391

60,970,130

Weighted-average number of common shares outstanding

60,156,352

70,096,000

Certain securities were excluded from the diluted earnings per share calculations ~~at September 30, 2009~~for the three months ended March 31, 2010 and ~~2010,~~2011, respectively, as the inclusion of the securities would be anti-dilutive to the ~~calculations.~~calculation. The amounts outstanding as of ~~September 30, 2009~~March 31, 2010 and ~~2010~~2011 for these instruments are as follows:

	September 30,		March 31,
	2009	2010	2010	2011
Options	9,186,614	9,563,055	9,446,610	10,705,519
Warrants	18,314,394	18,314,394	18,314,394	17,130,682

Note 13—Comprehensive Loss

The following table presents the Company’s comprehensive loss for the ~~nine~~three months ended ~~September 30, 2009~~March 31, 2010 and ~~2010:~~2011:

	Nine Months Ended September 30,						Three Months Ended March 31,
	2009			2010			2010			2011
Net loss attributable to Clean Energy Fuels Corp.	$	(31,331,396	)	$	(16,301,398	)	$	(24,367	)	$	(9,753	)
Derivative unrealized gains (losses)	1,490,825			(5,129,379		)	(3,865		)	708
Foreign currency translation adjustments	289,887			201,237			69			(702		)
Comprehensive loss	$	(29,550,684	)	$	(21,229,540	)	$	(28,163	)	$	(9,747	)

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 September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2009		2010		2009		2010		2010		2011
Stock options:
Stock-based compensation expense	$	3,551,992	$	3,259,927	$	10,572,136	$	9,221,647	$	3,040	$	3,377
Income tax benefit	—				—		—		—		—
Stock-based compensation expense, net of tax	$	3,551,992	$	3,259,927	$	10,572,136	$	9,221,647	$	3,040	$	3,377

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Stock Options

The following table summarizes the Company’s stock option activity during the ~~nine~~three months ended ~~September 30, 2010:~~March 31, 2011:

Number of
Shares

Weighted-Average
Exercise Price

Outstanding at December 31, 2009

10,348,188

$
9.57

Granted

446,750

16.70

Exercised

(1,073,542
)
10.05

Cancelled/Forfeited

(158,341
)
13.37

Outstanding at September 30, 2010

9,563,055

9.79

Exercisable at September 30, 2010

5,879,328

8.97

	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	571,000		13.97
Options exercised	(57,047	)	6.90
Options forfeited	(241,985	)	16.24
Outstanding, March 31, 2011	10,705,519		$	10.17	7.6	$	66,441
Exercisable, March 31, 2011	7,045,206		$	9.04	6.1	$	51,700

~~Table~~As of ~~Contents~~March 31, 2011, there was $26,223 of total unrecognized compensation cost related to unvested shares. That cost is expected to be recognized over a weighted-average period of 1.56 years. The total fair value of shares vested during the three months ended March 31, 2011 was $1,799.

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 three months ended March 31, 2010 and 2011 was $11,676 and $541, 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~~weighted-average assumptions used for grants in ~~2010:~~2011:

	~~Nine~~Three Months Ended ~~September 30, 2010~~March 31, 2011
Dividend yield	~~0.00~~0.00%	%
Expected volatility	~~87.69~~72.15% to 72.43%	%
Risk-free interest rate	~~2.08~~2.47% to 2.71%	%
Expected life in years	~~6.00~~6.0

~~Based on these assumptions, the weighted average~~The weighted-average grant date fair ~~value~~values of options granted during the ~~nine~~three months ended ~~September 30,~~March 31, 2010 ~~was $15.66.~~and 2011, were $11.91, and $9.11, 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 $3,040 and $3,377 of stock option expense during the three months ended March 31, 2010 and 2011, respectively. The Company has not recorded any tax benefit related to its stock option expense.

Note 15—~~Use of Estimates~~

The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and revenues and expenses during the reporting period. Actual results could differ from those estimates. 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 16—~~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 ~~have and~~ may ~~continue to~~ arise during the course of such audits as to facts and matters of law. On July 15, 2010, the Internal Revenue Service (“IRS”) sent the Company a letter disallowing approximately $5.1 million related to certain claims it 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. It is impossible at this time to determine the ultimate liabilities that the Company may incur resulting from any lawsuits, claims and proceedings, audits, commitments, contingencies and related matters or the timing of these liabilities, if any. If these matters were to be ultimately resolved unfavorably, an outcome not currently anticipated, it is possible that such outcome could have a material adverse effect upon the Company’s consolidated financial position or results of operations. However, the Company believes that the ultimate resolution of such actions will not have a material adverse affect on the Company’s consolidated financial position, results of operations, or liquidity.

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Note ~~17—~~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 ~~nine~~three months ended ~~September 30, 2009~~March 31, 2010 and ~~2010.~~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 ~~September 30, 2010~~March 31, 2011 are unchanged from December 31, ~~2009.~~

~~Table of Contents~~2010.

The Company is subject to taxation in the United States and various states and foreign jurisdictions. The Company’s tax years for ~~2005~~2006 through ~~2009~~2010 are subject to examination by various tax authorities. The Company is no longer subject to U.S. ~~or state~~ examination for years before ~~2005. The Company is currently under audit by the IRS~~2007 or state examinations for ~~tax~~ years ~~2006 through 2008.~~before 2006. On July 15, 2010, the ~~IRS~~Internal Revenue Service (“IRS”) sent the Company a letter disallowing approximately ~~$5.1 million~~$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 ~~September 30,~~March 31, 2010 includes a refund of approximately ~~$1.3 million~~$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 ~~18—~~17—Fair Value Measurements

~~On January 1, 2008,~~The Company follows the ~~Company adopted the~~FASB authoritative guidance for fair value measurements ~~which defines fair value, establishes a framework for measuring fair value and enhances disclosures about fair value measurements related~~with respect to ~~financial instruments. In December 2007, the Financial Accounting Standard Board (“FASB”) provided a one-year deferral of this guidance for non-financial~~ assets and ~~non-financial~~ liabilities ~~except those~~ that are ~~recognized or disclosed~~measured at fair value on a recurring basis ~~at least annually. Accordingly,~~and nonrecurring basis. Under the ~~Company adopted this guidance~~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 ~~non-financial~~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 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 ~~non-financial liabilities on January 1, 2009.~~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 ~~nine~~three months ended ~~September 30, 2010,~~March 31, 2011, the Company’s financial instruments consisted of natural gas futures contracts, debt instruments, ~~Series I warrants, and the~~ contingent consideration related to ~~both~~ its ~~BAF acquisition~~acquisitions, and its acquisition of the IMW Acquired Business. The Company remeasures its contingent consideration based on the discounted future cash flows of BAF and the IMW Acquired Business during the contingency periods, which expire December 31, 2011 and March 31, 2014, respectively. The Company records any change in its contingency obligation in selling, general and administrative expenses in its condensed consolidated statements of operations.Series I warrants. 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 ~~a Monte Carlo simulation model~~projected financial results for the respective entities, discounted to reflect the time value of money, to value ~~the Series I warrants, which requires the Company to make certain estimates including risk-free interest rates and the volatility of~~ its ~~stock price, among others. The Company’s futures contracts and~~ contingent consideration obligation are recorded in accrued liabilities for the short-term liability amount, and long-term liabilities for the long-term liability amount, and the Series I warrants are recorded in other long-term liabilities in the accompanying condensed consolidated balance sheet at September 30, 2010.obligations. The fair market value of the Company’s debt instruments approximated their carrying values at ~~September 30, 2010.~~

~~The following table reflects the fair value as defined by the authoritative guidance of the Company’s natural gas futures contracts~~March 31, 2010 and ~~Series I warrants at September 30, 2009:~~

Balance at
September 30,
2009

Quoted Prices
In Active Markets
for Identical Items
(Level 1)

Significant Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Natural gas futures contracts obligation

$
(836,342
)
$
—

$
(836,342
)
$
—

Series I warrants

$
(30,182,411
)
$
—

$
—

$
(30,182,411
)

2011. The Company ~~recorded~~uses either a ~~charge of $17,808,673 for~~Monte Carlo simulation model or the ~~nine month period ended September 30, 2009 in~~Black-Scholes model, depending on the ~~statement of operations associated with~~current terms, to value the Series I warrants.

~~Table~~ The Company considers a variety of ~~Contents~~

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 ~~following table provides a reconciliation~~Company also uses the implied volatilities of its short-term (i.e. 3 to 9 month) traded options and extrapolates the ~~beginning and ending balances for~~data over the remaining term of the Series I warrants, ~~at fair value using significant other unobservable inputs (Level 3) for~~which was approximately 5.08 years as of March 31, 2011. Given that the ~~nine months ended September 30, 2009:~~

Series I Warrants

Beginning Balance, January 1, 2009

$
(12,373,738
)
Total charges included in earnings for the period

(17,808,673
)
Purchases

—

Sales

—

Transfers In/Out

—

Ending Balance, September 30, 2009

$
(30,182,411
)

~~The following table reflects~~extrapolation beyond the ~~fair value as defined by the authoritative guidance~~term of the ~~Company’s natural gas futures contracts, Series I warrants and contingent consideration at September 30, 2010:~~

Balance at
September 30,
2010

Quoted Prices
In Active Markets
for Identical Items
(Level 1)

Significant Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Natural gas futures contracts obligation

$
(4,970,244
)
$
—

$
(4,970,224
)
$
—

Series I warrants

$
(23,863,637
)
$
—

$
—

$
(23,863,637
)
Contingent consideration

$
(12,400,000
)
$
—

$
—

$
(12,400,000
)

~~The Company recorded~~short term exchange traded options is not based on observable market inputs for a ~~gain of $5,876,854 for the nine month period ended September 30, 2010 in the statement of operations associated with the Series I warrants.~~

~~The following table provides a reconciliation~~significant portion of the ~~beginning and ending balances for~~remaining term of the ~~contingent consideration and~~warrants, the Series I warrants athave been classified as a Level 3 fair value ~~using significant unobservable inputs (Level 3) for~~determination in the ~~nine months ended September 30, 2010:~~

Contingent
Consideration

Series I Warrants

Beginning Balance, January 1, 2010

$
(3,100,000
)
$
(29,740,491
)
Total gain included in earnings for the period

—

5,876,854

IMW Purchased obligations

(9,300,000
)
—

Sales

—

—

Transfers In/Out

—

—

Ending Balance, September 30, 2010

$
(12,400,000
)
$
(23,863,637
)

~~Note 19—Recently Adopted Accounting Changes and Recently Issued Accounting Standards~~

In June 2008, the FASB reached a consensus on determining whether an instrument (or embedded feature) is indexed to an entity’s own stock. The FASB concluded, among other things, that contingent and other adjustment features in equity-linked financial instruments are consistent with equity indexation if they are based on variables that would be inputs to a “plain vanilla” option or forward pricing model and they do not increase the contract’s exposure to those variables. The Company’s Series I warrants issued on October 28, 2008 are linked to the Company’s own equity shares; however, the investor has protective pricing features commonly referred to as “~~down-round”~~ protection, whereby the conversion price potentially resets if the common stock price of the Company declines after issuance or shares are issued by the Company at prices below the exercise price of the warrants. As a result of this guidance, effective January 1, 2009, the Company accounts for the Series I warrants as a derivative. The Company recorded a cumulative-effect adjustment of approximately $2.6 million to opening retained earnings and reclassed approximately $9.8 million from additional paid-in capital to long-term liabilities on the date of adopting this guidance, January 1, 2009. During 2009 and during the nine month period ended September 30, 2010, the Company recorded a charge of $17.4 million and a gain of $5.9 million, respectively, related to valuing the Series I warrants.

In October 2009, the FASB issued new authoritative guidance on multi-deliverable revenue arrangements. This guidance establishes requirements that must be met for an entity to recognize revenue from the sale of a delivered item that is part of a multiple-element arrangement when other items have not yet been delivered. One of those current requirements is that there be objective and reliable evidence of the standalone selling price of the undelivered items, which must be supported by either vendor-specific objective evidence (“VSOE”) or third party evidence (“TPE”). This guidance amends previoustable below.

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~~guidance~~The following tables provide information by ~~eliminating the requirement~~level for assets and liabilities that all undelivered elements have VSOE or TPE before an entity can recognize the portion of an overall arrangement fee that is attributable to items that already have been delivered. In the absence of VSOE or TPEare measured at fair value on a recurring basis:

Description	Balance at March 31, 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	$	3,363	$	—	$	3,363	$	—
Contingent consideration obligations	10,483		—		—		10,483
Series I warrants	17,448		—		—		17,448

The following tables provide a reconciliation of the ~~standalone selling price for one or more delivered or undelivered elements~~beginning and ending balances of items measured at fair value on a recurring basis in ~~a multiple-element arrangement, entities will be required to estimate~~ the ~~selling prices of those elements. The overall arrangement fee will be allocated to each element (both delivered~~table above that used significant unobservable inputs (Level 3).

Liabilities: Contingent Consideration	March 31, 2010		March 31, 2011
Beginning Balance	$	3,100	$	11,200
Business combinations	—		—
Total (gain) loss included in earnings	300		(717		)
Payments	—		—
Transfers In/Out	—		—
Ending Balance	$	3,400	$	10,483

Liabilities: Series I Warrants	March 31, 2010		March 31, 2011
Beginning Balance	$	29,741	$	14,148
Total loss included in earnings	18,605		3,300
Issuance of warrants	—		—
Exercise of warrants	—		—
Transfers In/Out	—		—
Ending Balance	$	48,346	$	17,448

Note 18—Recently Adopted Accounting Changes and undelivered items) based on their relative selling prices, regardless of whether those selling prices are evidenced by VSOE or TPE or are based on the entity’s estimated selling price. Application of the “residual method” of allocating an overall arrangement fee between delivered and undelivered elements will no longer be permitted under this new guidance. Additionally, the new guidance will require entities to disclose more information about their multiple-element revenue arrangements. The revised guidance is effective for fiscal periods beginning on or after June 15, 2010. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements.Recently Issued Accounting Standards

InOn January ~~2010,~~1, 2011, the Company adopted changes issued by the FASB ~~issued new accounting guidance which intended~~ to ~~improve disclosures about~~disclosure requirements for fair value measurements. ~~The guidance requires entities~~Specifically, the changes require a reporting entity to disclose, ~~significant transfers in and out of fair value hierarchy levels, the reasons for the transfers and to present information about purchases, sales, issuances and settlements separately~~ 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). ~~Additionally,~~In addition, the ~~guidance clarifies that~~changes require a reporting entity ~~should provide~~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 ~~each class of assets and liabilities and disclose~~ the ~~inputs and valuation techniques used for fair value measurements using significant other observable inputs (Level 2) and significant unobservable inputs (Level 3). The Company has~~transfers. These changes were applied to the ~~new disclosure requirements as of~~disclosures in note 17 to the Company’s condensed consolidated financial statements contained elsewhere herein.

On January 1, ~~2010,~~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. Based on the most recent impairment review of the Company’s goodwill (2010 fourth quarter), the adoption of this ~~guidance~~pronouncement did not have ~~a material~~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.

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Note ~~20—~~19—Volumetric Excise Tax Credit (VETC)

The Company ~~recorded~~records its VETC credits as revenue in its condensed consolidated statements of operations as the credits ~~were~~are fully refundable and ~~did~~do not need to offset income tax liabilities to be received. VETC revenues for the ~~nine~~three month periods ended ~~September 30, 2009~~March 31, 2010 and ~~2010~~2011, were ~~approximately $11.8 million~~$0 and ~~$0.0 million,~~$4,217, respectively. The legislation providing for VETC ~~expired on~~was reinstated in the fourth quarter of 2010, made retroactive to January 1, 2010 and extended to December 31, ~~2009.~~2011. During the fourth quarter of 2010, the Company recorded $16,042 of VETC revenue, which included $3,595 related to the three month period ended March 31, 2010.

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, ~~2009~~2010 contained in our ~~2009~~2010 Annual Report on Form 10-K filed with the SEC on March 10, ~~2010,~~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 ~~2009~~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 ~~2009~~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.

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~~Overview~~

We provide natural gas solutions for vehicle fleets primarily in the United ~~States and Canada.~~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 ~~compressed natural gas~~CNG station in Lima, Peru, through our joint venture, Clean Energy del Peru. In August 2008, we acquired 70% of the outstanding membership ~~interest~~interests of ~~Dallas Clean Energy, LLC (“DCE”).~~DCE. DCE owns a facility that collects, processes and sells renewable biomethane ~~collected from a~~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, ~~the Company, acting through certain of its subsidiaries,~~we completed ~~its~~the purchase of ~~the~~IMW, a company that manufactures and services advanced, non-lubricated natural gas fueling ~~compressor~~compressors and related ~~equipment manufacturing~~equipment. On December 15, 2010, we acquired Northstar, which provides design, engineering, construction and ~~servicing business (the “IMW Acquired Business”~~maintenance services for LNG and liquefied to compressed natural gas (“LCNG”) ~~of I.M.W. Industries Ltd., a British Columbia corporation (“IMW”).~~fueling stations.

~~The following~~Overview

This overview discusses matters on which our management primarily focuses in evaluating our financial condition and operating ~~performance as well as recent and anticipated business trends.~~performance.

Sources of revenue. We generate the vast majority 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 ~~our~~ DCE, ~~joint venture,~~ sales of natural gas ~~vehicles~~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 ~~the IMW Acquired Business.~~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.

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Key operating data. In evaluating our operating performance, our management focuses primarily on: (1) the amount of CNG and LNG gasoline gallon equivalents delivered (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,~~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, ~~2007,~~ 2008, 2009, and ~~2009~~2010 and for the three ~~and nine~~ months ended ~~September 30, 2009~~March 31, 2010 and ~~2010:~~2011:

Gasoline gallon equivalents delivered (in millions)	Year Ended December 31, 2007			Year Ended December 31, 2008			Year Ended December 31, 2009			Three Months Ended September 30, 2009			Three Months Ended September 30, 2010			Nine Months Ended September 30, 2009			Nine Months Ended September 30, 2010			Year Ended December 31, 2008			Year Ended December 31, 2009			Year Ended December 31, 2010			Three Months Ended March 31, 2010			Three Months Ended March 31, 2011
CNG	48.0			47.6			67.9			19.9			20.2			48.3			60.0			47.6			67.9			81.4			19.2			22.7
Biomethane	—			2.0			6.4			1.9			1.8			4.3			5.6			2.0			6.4			7.4			1.9			1.5
LNG	27.3			23.9			26.7			7.7			9.3			18.9			25.4			23.9			26.7			33.9			7.5			11.3
Total	75.3			73.5			101.0			29.5			31.3			71.5			91.0			73.5			101.0			122.7			28.6			35.5

Operating data
Gross margin	$	32,055,904		$	27,098,948		$	48,582,410		$	12,424,121		$	12,144,877		$	32,693,556		$	36,993,856		$	27,099		$	48,582		$	69,945		$	11,430		$	18,337
Net income (loss)	(8,894,362		)	(44,462,674		)	(33,248,701		)	(18,460,583		)	(1,829,874		)	(31,331,396		)	(16,301,398		)
Net loss																						(44,463		)	(33,249		)	(2,516		)	(24,367		)	(9,753		)

Key trends in ~~2007,~~ 2008, ~~and~~ 2009, 2010 and the first ~~nine~~three months of ~~2010.~~2011. According to the U.S. Energy Information Administration, demand for natural gas fuels in the United States increased by approximately ~~29%~~26% during the period January 1, ~~2007~~2008 through December 31, ~~2009.~~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 ~~211~~238 at ~~September 30, 2010~~March 31, 2011 (a ~~43.5%~~61.9% 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 ~~2009~~2010 increased by ~~77.8%~~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 ~~nine~~three months of ~~2010,~~2011, we ~~also~~ experienced reduced margins ~~in certain markets, particularly in the municipal transit and refuse sector.~~related to our fueling business compared to historical margins. The reduction in margins is primarily a result of increased ~~competition~~O&M volumes with our transit and ~~sales agreements with larger entities~~refuse customers, that have ~~greater pricing leverage. Also, in many cases,~~lower margins, becoming a larger part of our agreements with our customers, including governmental agencies, are subject to a competitive bidding process and we may be required to reduce our prices to maintain our contracts as they come up for bid. We also have significant contracts with government entities that are experiencing large budget deficits and these customers have and may continue to demand price reductions for

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our services. In addition, in May and June of 2009, we acquired four compressed natural gas operations and maintenance services contracts with municipal transit agencies that have significant volume but smaller margins than we typically generate on our fuel sales. As a result, the overall ~~average margin on our fuel sales across our business decreased during these periods.~~fueling business. We believe that our margins on fuel sales will improve in the future to the extent we are successful in ~~growing~~increasing our retail CNG and LNG fueling operations ~~which is where~~as an overall component of our fueling business. Within our overall fueling business, we earn our highest ~~margin, relative to our lower margin operations, such as municipal transit. If we are unsuccessful~~margins in ~~growing~~ our retail ~~CNG~~fueling operations.

During the first three months of 2011, prices for oil, gasoline, diesel fuel and ~~LNG fueling operations,~~natural gas generally increased. Oil increased from a low of $92.19 per barrel in January 2011 to a price of $106.72 per barrel on March 31, 2011. In California, average retail prices for gasoline have increased from a low of $3.36 per gallon in January 2011 to $4.07 per gallon at March 31, 2011, and average retail prices for diesel fuel have increased from a low of $3.51 per diesel gallon in January 2011 to $4.26 per diesel gallon at March 31, 2011. Higher gasoline and diesel prices typically improve our margins on fuel sales to the extent we ~~may experience reduced margins. We may also lose contracts with governmental customers if we are unwilling~~price fuel at a discount to gasoline or ~~unable~~diesel. During this time period, the price for natural gas slightly declined. The NYMEX price for natural gas fluctuated from a high of $4.22 per MMbtu in January 2011 to ~~reduce our prices or lose in the competitive bidding process, which would reduce our volumes. For example, MTS of San Diego, which represented approximately six million gasoline gallon equivalents~~$3.79 per MMbtu at March 31, 2011. The average retail sales price of our CNG volume in 2009, recently conducted a competitive bidding procurement and awarded the contract to a competitor beginning July 27, 2010. We will need to grow our business with non-government entities to replace volumes lost in competitive bid procurements when we are not successful in retaining the contracts.

~~Recent developments.~~ On September 7, 2010, the Company, acting through certain of its subsidiaries, completed its purchase of the IMW Acquired Business. The IMW Acquired Business manufactures and services advanced natural gas fueling compressors and related equipment for the global natural gas fueling market. The IMW Acquired Business is headquartered near Vancouver, British Columbia, has a second manufacturing facility near Shanghai, China and has sales and service offices in Bangladesh, Columbia and the United States. We believe the acquisition of the IMW Acquired Business will enable us to participatefuel sold in the ~~growth~~Los Angeles metropolitan area remained steady at $2.60 for first three months of ~~natural gas vehicle fueling overseas, as well as in North America, and enable us to offer our customers a wider variety of natural gas vehicle fueling solutions.~~

On August 30, 2010, we executed a non-binding Letter of Intent (the “LOI”) to acquire all of the outstanding interests or substantially all of the assets of Wyoming Northstar Incorporated and its affiliates (collectively, “Northstar”). Northstar is primarily engaged in manufacturing, constructing and servicing LNG and LCNG fueling facilities. Subject to the completion of our due diligence investigation of Northstar and the execution of a definitive purchase agreement, we agreed to purchase the Northstar business for consideration of up to $16 million, with $6.5 million payable at closing and a portion of the consideration to be allocated to employee retention programs. The remaining consideration will be payable in equal payments over the five years following the acquisition. The acquisition is subject to the final approval of a Committee of our Board of Directors and Northstar’s Board of Directors. We plan to complete due diligence and negotiation of the definitive agreement as soon as possible, but there is no guarantee that we will be successful in completing the acquisition.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.~~production and supply. A 2008 Navigant Consulting, Inc. study indicates that as a result of new unconventional

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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 ~~become~~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 ~~2009~~2010 BP Statistical Review of World Energy, on a global basis, the ratio of proven natural gas reserves to ~~2008~~2009 natural gas production was ~~44%~~37% greater than the ratio of proven crude oil reserves to ~~2008~~2009 crude oil production. This analysis suggests significantly greater ~~longer~~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 ~~acquisition~~acquisitions of ~~the~~ IMW ~~Acquired Business,~~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. We also anticipate expanding our sales of CNG and LNG in the other markets in which we operate, including ~~public transit,~~ regional trucking, refuse hauling, airports and ~~airports.~~public transits. 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.

Continuing high unemployment rates and reduced economic activity may reduce our opportunities to attract new fleet customers. Many governmental entities ~~which represented approximately 37% of our revenues for the nine months ended September 30, 2010,~~ 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.

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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.

~~We anticipate that we will need to raise capital in order to continue to fund the growth of our business.~~ Our ~~current~~ business plan calls for approximately ~~$17.1~~$70.7 million in capital expenditures from ~~October~~April 1, ~~2010~~2011 through ~~December 31, 2010,~~the end of 2011, primarily related to construction of new fueling stations. This amount excludes 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, expansion of our DCE landfill gas processing~~ plant or for other acquisitions or investments in companies or assets in the natural gas fueling infrastructure, services and production industries, including biomethane production. We will need to raise additional capital as necessary to fund any expansion of our California LNG ~~plant or DCE landfill gas~~ 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, any decision to expand our California LNG plant, ~~or DCE gas processing 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, ~~expand our California LNG plant or DCE gas processing plant,~~ develop natural gas fueling infrastructure and invest in strategic transactions or acquisitions, and reduce our ability to grow our business and generate increased revenues.

~~Volatility in operating results related to Series I warrants.~~ Beginning January 1, 2009, under recent accounting guidance, we are required to record the change in the fair market value of our Series I warrants in our financial statements until the Series I warrants are exercised or expire. 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. We recognized a (gain) loss of $0.2 million, $2.2 million, $15.4 million, ($0.4) million, $18.6 million, ($16.6) million, and ($7.9) million, related to recording the fair market value changes of our Series I warrants in the quarters ended March 31, 2009, June 30, 2009, September 30, 2009, December 31, 2009, March 31, 2010, June 30, 2010, and September 30, 2010, respectively. Our earnings or loss per share have been and will likely continue to be materially impacted by future gains or losses we are required to take as a result of valuing our Series I warrants.

~~Volatility in operating results related to BAF & IMW 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 the IMW Acquired Business, in our financial statements through the contingency period, which expires December 31, 2011 for BAF, and on March 31, 2014 for the IMW Acquired Business.

If the anticipated results of BAF or the IMW Acquired Business 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 losses of $0.3 million and $0.2 million during the quarters ended March 31, 2010 and June 30, 2010, respectfully, and we recognized a gain of $0.5 million during the quarter ended September 30, 2010. Subsequent to September 7, 2010, the closing date of the acquisition of the IMW Acquired Business, we determined that no adjustment is required to the value of the contingent consideration owed to the former IMW shareholder during the quarter ended September 30, 2010. Our earnings or loss per share may be materially impacted by future gains or losses we are required to take as a result of changes in the contingent consideration amount.

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.

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Operations

We generate revenues principally by selling CNG and LNG and providing O&M services to our vehicle fleet customers. For the ~~nine~~three months ended ~~September 30, 2010,~~March 31, 2011, CNG and biomethane (together) represented ~~72%~~68% and LNG represented ~~28%~~32% 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 ~~vehicles~~vehicle systems by 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 ~~the~~ IMW, ~~Acquired Business. Substantially all~~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, ~~as owners of LNG stations tend to operate~~ and ~~maintain their own stations. Substantially~~substantially all of our station sale and leasing revenues have been generated from CNG stations.

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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 ~~two~~five public LNG stations and for non-vehicle use. ~~For the first nine months of 2010,~~During 2011, we procured ~~24.8%~~43% 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,~~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 also provided price caps to certain customers on the index component of their index-plus pricing arrangement for certain contracts we entered into on or prior to December 31, 2006. Effective January 1, 2007, we ceased offering price-cap contracts to our customers, but we will continue to perform our obligations under price-cap contracts we entered into before January 1, 2007. We will continue to offer fixed price contracts as appropriate and consistent with our natural gas hedging policy ~~adopted~~that was revised in May 2008. Our LNG contracts provide that we charge our customers periodically based on the volume of LNG ~~supplied.~~supplied or sold.

Government Incentives

~~From~~Since October 1, 2006, ~~through December 31, 2009,~~ we have received a ~~volumetric excise~~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 to certain customers. The tax credit was responsible for a significant amount of our historical revenues.~~fuel. Based on the service relationship ~~we had~~ with our customers, either we or our customers were able to claim the credit. We recorded these tax credits as revenues in our ~~condensed~~ consolidated statements of operations as the credits ~~were~~are fully refundable and ~~did~~do not need to offset tax liabilities to be received. As such, the credits ~~were~~are not deemed income tax credits under the accounting guidance applicable to income taxes. In addition, we believe the credits ~~were~~are properly recorded as revenue because we often ~~incorporated~~incorporate the tax credits into our pricing with our customers, thereby lowering the actual price per gallon we ~~charged~~charge them. The ~~tax credit expired~~program providing for the VETC expires on December 31, ~~2009. If~~2011.

On July 15, 2010, the ~~tax credit is not reinstated, our revenue~~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 ~~future periods will be materially less than it would have been~~an examination appeal meeting with the ~~tax credit~~IRS. We believe our claims were properly made and ~~our ability~~expect to ~~attract new customers, or retain old customers, may also be reduced.~~continue to contest the IRS’s determination.

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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 three months ended March 31, 2011, Northstar contributed approximately $3.6 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

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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 ~~September 30, 2010,~~March 31, 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. ~~From~~For the ~~acquisition date through December 31, 2008, for the year ended December 31, 2009 and for the nine~~three months ended ~~September 30,~~March 31, 2010 and 2011, DCE generated approximately ~~$1.8 million, $7.9~~$1.0 million and ~~$8.5~~$2.8 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.~~facility (the “Shell Gas Sale Agreement”).

DCE retains the right to reserve from the ~~gas sale agreement~~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, ~~with Shell,~~ 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 ~~fourth quarter~~first half of ~~2011.~~2012.

The sale price for the gas under the ~~agreement with~~ Shell Gas Sale Agreement is ~~fixed and increases in 2011.~~fixed. The sale price for the gas represents a substantial premium to the current prevailing prices for natural gas at ~~November 9, 2010.~~

Under the terms of the agreement, DCE has retained the rights to any available greenhouse gas emission reduction credits that may be generated through the operation of the landfill gas collection and processing facility, provided that DCE must supply Shell with a sufficient number of such credits to enable the end-user of the gas to meet applicable “net-zero” emissions requirements under the relevant renewable portfolio standard with respect to use of the biomethane in power generation. Given the complex and changing standards and requirements in the market for greenhouse gas emission reduction credits, there can be no guarantee that any greenhouse gas emission credits will be generated or sold as a result of DCE’s landfill gas operations.March 31, 2011.

The ~~gas sale agreement~~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 after the date of the agreement 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).

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On March 25, 2011, our 70% owned 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 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. We, in turn, used the proceeds from the payoff of the DCE Loan to repay approximately $8,000 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 our 70% owned subsidiary, 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 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.

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 March 31, 2011, $24,668 was included as long term assets 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 March 31, 2011, DCEMB was in compliance with all such debt covenants.

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Vehicle ~~Conversion~~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.~~development services. BAF’s vehicle conversions include taxis, ~~limousines,~~ 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 ~~vehicles~~vehicle conversion systems that ~~have been converted~~allow gasoline and diesel vehicles to run on natural ~~gas by BAF.~~gas. The majority of BAF’s revenue during ~~2009~~2010 was derived from sales of converted natural gas service vans to AT~~&T.~~&T and Verizon. During the ~~fourth~~first quarter of ~~2009~~2010 and ~~for the nine months ended September 30, 2010,~~2011, BAF contributed approximately ~~$6.9~~$9.0 million and ~~$29.3~~$3.6 million, respectively, to our revenue.

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Natural Gas Fueling Compressors

On September 7, 2010, ~~the Company, acting through certain of its subsidiaries,~~we completed ~~its~~our purchase of ~~the~~IMW. IMW ~~Acquired Business. The IMW Acquired Business~~ manufactures and services advanced, non-lubricated natural gas fueling compressors and related equipment for the global natural gas fueling market. ~~The~~ IMW ~~Acquired Business~~ is headquartered near Vancouver, British Columbia, has a second manufacturing facility near Shanghai, China and has sales and service offices in Bangladesh, Columbia and the United States. ~~Since~~For the ~~September 7, 2010 acquisition date, the~~three months ended March 31, 2011, IMW ~~Acquired Business~~ contributed approximately ~~$3.3~~$16.7 million to our ~~revenue, excluding intercompany sales to us.~~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 ~~but a few~~ of our futures contracts entered into prior to June 30, 2008 have ~~historically~~ 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. ~~For example, we~~We experienced a derivative ~~gains~~loss of ~~$5.7~~$0.3 million ~~for~~in the ~~three months~~year ended December 31, 2008. Subsequent to June 30, 2008, ~~and derivative losses of $6.0 million and $0.3 million~~our futures contracts did qualify for ~~the three months ended September 30, 2008 and December 31, 2008, respectively. We~~hedge accounting, so we had no derivative gains or losses ~~for~~in the years ended December 31, 2009 and 2010 and during the three ~~months~~month period ended March 31, 2007, June 30, 2007, September 30, 2007, December 31, 2007, March 31, 2008, March 31, 2009, June 30, 2009, September 30, 2009, December 31, 2009, March 31, 2010, June 30, 2010 and September 30, 20102011 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 ~~September 30, 2010,~~March 31, 2011, we had ~~$5.9~~$4.8 million on deposit in margin accounts, which are included in prepaid expenses and other current assets and notes receivable and other long-term assets ~~on the~~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 ~~recent accounting~~Financial Accounting Standards Board (“FASB”) authoritative guidance, we are required to record the change in the fair market value of our Series I warrants in our consolidated financial statements. 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. We recognized a loss (gain) ~~loss~~ of ~~$0.2 million, $2.2 million, $15.4 million, ($0.4) million,~~ $18.6 million ~~($16.6) million,~~ and ~~($7.9)~~$3.3 million related to recording the fair market value changes of our Series I warrants in the ~~quarters~~three months ended March 31, ~~2009, June 30, 2009, September 30, 2009, December 31, 2009, March 31, 2010, June 30,~~ 2010 and ~~September 30, 2010, respectively (see~~2011, respectively. See note 1917 to our condensed consolidated financial statements contained elsewhere ~~herein).~~herein. Our earnings or loss per share ~~have been and likely will continue to~~may be materially impacted by future gains or losses we are required to take 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 March 31, 2011, 2,130,682 of the Series I warrants remained outstanding.

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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 ~~the~~ IMW ~~Acquired Business~~ in our financial statements through the contingency period, which expires on December 31, 2011 for BAF and on March 31, 2014 for ~~the IMW Acquired Business.~~ IMW.

If the anticipated results of BAF or ~~the~~ IMW ~~Acquired Business~~ 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 ~~losses~~a loss of $0.3 million ~~and $0.2 million~~ during the ~~quarters~~three months ended March 31, 2010 ~~and June 30, 2010, respectfully,~~ and we recognized a gain of ~~$0.5~~$0.1 million during the ~~quarter~~months ended ~~September 30, 2010. Subsequent to September 7, 2010,~~March 31, 2011. To record the ~~closing date of the acquisition of the IMW Acquired Business, we determined that no adjustment is required to~~change in the value of the IMW contingent consideration, ~~owed to the former IMW shareholder~~we recognized a gain of $0.6 million during the ~~quarter~~three months ended ~~September 30, 2010.~~

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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 1.1.0. Beginning in the quarter ended June 30, 2009, we must also maintain a ~~specific minimum~~ 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 our 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. ~~One of our bank covenants is a requirement to maintain accounts receivable balances from certain subsidiaries above $8.0 million at each quarter-end.~~ To the extent natural gas prices continue to fall, or our volumes decline we could violate this covenant in the future. Beginning with the quarter ended June 30, 2009, we are required to maintain a debt service ratio, as defined, of not less than 1.5 to 1. We were not in compliance with this covenant as of the quarter ended September 30, 2010 and received a waiver from the bank. The entire amount of the Facility B Loan is shown as current in the accompanying condensed consolidated balance sheets based on prevailing accounting guidance. To the extentor our operating results do not materialize as planned, we could violate ~~this covenant again~~our covenants in the future. In the event we violate ~~any of the~~our covenants, ~~under the Credit Agreement,~~ we would seek ~~another~~a waiver from the ~~bank.~~bank, which the bank is not obligated to grant. We were in compliance with all of our covenants as of March 31, 2011.

Pursuant to ~~the recent~~our acquisition of ~~the~~ IMW, ~~Acquired Business,~~ our credit agreement with HSBC also requires that ~~a subsidiary of the Company (the “Acquisition Subsidiary”) comply~~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 ~~the Acquisition Subsidiary~~IMW shall not permit 1) its ratio of debt to tangible net worth to be greater than 3.25 to 11.0 until December 31, 2010 and greater than ~~3.00~~4.0 to ~~1 from January~~1.0 on or after March 31, 2011 and greater than 3.0 to 1.0 on or after July 1, 2011, ~~onward,~~ 2) its tangible net worth to at anytime be below CAD$~~3,000,000~~3,000 and 3) its ratio of current assets to current liabilities to be less than 1.15 to 11.0 until December 31, 2010 and less than 1.25 to ~~1 from~~1.0 on or after January 1, ~~2011 onward.~~2011. Should ~~the Acquisition Subsidiary’s~~IMW’s operating results not materialize as planned, itwe could violate these covenants. If itwe were to violate a covenant, itwe would seek a waiver from the bank, which the bank is not obligated to grant. If the bank ~~does not~~were to decline to grant a waiver, all of the obligations under the credit agreement would be due and payable. ~~The Acquisition Subsidiary~~IMW was in compliance with these covenants as of ~~September 30, 2010.~~March 31, 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 March 31, 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 ~~2009~~2010 Annual Report on Form 10-K. For the quarter ended March 31, 2011, there were no material changes to our risk management activities.

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Critical Accounting Policies

For the ~~first nine~~three months ~~of 2010,~~ended March 31, 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 ~~2009~~2010 Annual Report on Form 10-K.

Recently Issued Accounting Pronouncements

For a description of recently issued accounting pronouncements, see note 1918 to our condensed consolidated financial statements contained elsewhere herein.

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Results of Operations

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

	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2009		2010		2009		2010		2010		2011
Statement of Operations Data:
Revenue:
Product revenues	84.3	%	89.8	%	89.0	%	89.1	%	87.9	%	89.6	%
Service revenues	15.7		10.2		11.0		10.9		12.1		10.4
Total revenues	100.0		100.0		100.0		100.0
Total operating revenues									100.0		100.0
Operating expenses:
Cost of sales:
Product cost of sales	52.5		68.3		59.1		66.4		65.4		67.1
Service cost of sales	7.7		5.1		4.3		4.9		5.3		4.8
Selling, general and administrative	33.6		34.7		37.7		34.5		35.0		27.6
Depreciation and amortization	14.5		12.1		13.7		12.1		12.8		11.0
Derivative loss (gain) on Series I warrant valuation	49.4		(17.2	)	19.9		(4.6	)
Derivative loss on Series I warrant valuation									47.7		5.1
Total operating expenses	157.7		103.0		134.7		113.3		166.2		115.6
Operating loss	(57.7	)	(3.0	)	(34.7	)	(13.3	)	(66.2	)	(15.6	)
Interest expense, net	(0.9	)	(0.2	)	(0.4	)	0.0
Other income (expense), net	(0.3	)	(0.7	)	(0.3	)	(0.3	)
Income from equity method investments	0.2		0.2		0.1		0.2
Interest income (expense), net									0.3		(1.2	)
Other income									0.1		0.9
Income from equity method investment									0.2		0.3
Loss before income taxes	(58.7	)	(3.7	)	(35.3	)	(13.4	)	(65.6	)	(15.6	)
Income tax benefit (expense)	(0.2	)	(0.6	)	(0.3	)	0.7		3.1		1.1
Net loss	(58.9	)	(4.3	)	(35.6	)	(12.7	)	(62.5	)	(14.5	)
Loss (income) attributable to noncontrolling interest	(0.3	)	0.2		0.5		0.0
Income (loss) of noncontrolling interest									0.0		(0.4	)
Net loss attributable to Clean Energy Fuels Corp.	(59.2	)	(4.1	)	(35.1	)	(12.7	)	(62.5	)	(14.9	)

Three Months Ended ~~September 30, 2010~~March 31, 2011 Compared to Three Months Ended ~~September 30, 2009~~March 31, 2010

Revenue. Revenue increased by ~~$14.5~~$26.3 million to ~~$45.7~~$65.3 million in the three months ended ~~September 30, 2010,~~March 31, 2011, from ~~$31.2~~$39.0 million in the three months ended ~~September 30, 2009.~~March 31, 2010. A portion of this increase was the result of an increase in the number of gallons delivered from ~~29.5~~28.6 million gasoline gallon equivalents to ~~31.3~~35.5 million gasoline gallon equivalents. ~~The~~Our increase in CNG volume was primarily ~~due to~~from six new refuse customers (one of which consists of four new stations), four new stations from an ~~increase in LNG sales of 1.6~~existing transit customer, one new airport customer, and one new regional trucking customer, which together accounted for 5.4 million gallons of which 1.1 million gallons was from our port trucking customers and 0.4 million gallons was from our new refuse customers (Republic Waste Services of Southern California and Consolidated Disposal Services). We also experienced an increase of 0.3 million gallons inthe CNG volume ~~between periods, which was due to a combination of a 0.9 million gallon increase~~increase. The volume growth from our existing airport and ~~refuse customers,~~public fueling network, combined with the volume growth from our share of our joint venture in Peru, ~~and a 0.5~~contributed 1.4 million ~~gallon increase from new refuse and regional trucking customers.~~gallons of the CNG volume increase. These CNG volume increases were offset by a 3.3 million gallon decrease related to the ~~1.1 million gallons decrease in~~loss of two transit volumes as a result of a competitive bidding procurement that was awarded to a competitor. Revenue also increased by $9.3 million between periods from sales of natural gas vehicle equipment by BAF, which we acquired on October 1, 2009.customers. We also experienced an increase of 3.8 million gallons in LNG volume between periods, which was primarily due to 3.1 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 ~~$1.6~~ $6.2

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million increase, excluding Northstar, in station construction revenues between periods. Our effective price per gallon was $1.00 in the three months ended September 30, 2010, which represents a $0.07 per gallon increase from $0.93 in the three months ended September 30, 2009. The increase wasperiods primarily due to the completion of four new CNG stations for a refuse customer and the sale of an ~~increase in natural gas prices between periods and an increase in the price we are charging for~~existing station to one of our ~~biomethane.~~other refuse customers. Our ~~acquisition~~acquisitions of ~~the~~ IMW ~~Acquired Business~~ on September 7, 2010 and Northstar on December 15, 2010 contributed ~~$3.3~~$16.7 million and $3.6 million, respectively, to our increased revenue between periods. Revenue attributable to VETC also increased between periods as we recorded $4.2 million of revenue related to fuel tax credits. We did not record any revenue related to fuel tax credits in the first quarter of 2010 as the fuel tax credits expired on December 31, 2009 and were not reinstated until the fourth quarter of 2010. During the fourth quarter of 2010, we recorded $16.0 million of VETC revenue, of which $3.6 million was related to the three months ended March 31, 2010. These increases were offset by the decrease in our ~~fuel tax~~effective price per gallon that we charged to our customers between periods. Our effective price per gallon was $0.86 in the three months ended March 31, 2011, which represents a $0.18 per gallon decrease from $1.04 in the three months ended March 31, 2010. The decrease was primarily due to a higher percentage of O&M contracts in the first quarter of 2011, which generate less revenue per gallon than contracts where we supply the natural gas commodity. Revenue also decreased by $5.4 million between periods ~~as the fuel tax credits expired on December 31, 2009. We did not record any fuel tax revenues in the third quarter~~due to decreased sales of ~~2010 and we recorded $3.7 million of revenue related to fuel tax credits in the third quarter of 2009.~~natural gas vehicle equipment by BAF.

Cost of sales. Cost of sales increased by ~~$14.7~~$19.4 million to ~~$33.5~~$47.0 million in the three months ended ~~September 30, 2010,~~March 31, 2011, from ~~$18.8~~$27.6 million in the three months ended ~~September 30, 2009.~~March 31, 2010. Our cost of sales primarily increased between periods as a result of delivering more volume to our ~~customers together with $6.7~~customers. Our acquisition of IMW on September 7, 2010 and Northstar on December 15, 2010 contributed $15.0 million and $2.6 million, respectively, to our increased cost of ~~increased costs related to BAF’s vehicle equipment~~ sales ~~which we began to recognize on October 1, 2009 when we acquired the company.~~between periods. We also experienced a ~~$1.6~~$5.1 million increase in station construction costs between periods. ~~We also recognized $2.4 million in costs related to sales of compressor equipment and services~~These increases were offset by the ~~IMW Acquired Business, which we began to recognize on September 7, 2010 when we acquired the IMW Acquired Business. Our~~decrease in our effective cost per gallon ~~increased by $0.09~~of $0.12 per gallon, ~~during~~to $0.62 per gallon, in the ~~period to $0.73 per gallon.~~three months ended March 31, 2011. This ~~increase~~decrease was primarily the result of ana higher percentage of O&M contracts in the first quarter of 2011 that are included in our volume totals but do not increase inour cost of sales amount significantly as we do not pay for the natural gas ~~prices~~consumed at the properties. We also experienced a $4.0 million decrease in costs related to BAF’s vehicle equipment sales between ~~periods.~~

~~Table~~periods, as BAF’s sales of ~~Contents~~natural gas vehicle equipment decreased.

Selling, general and administrative. Selling, general and administrative expenses increased by ~~$5.4~~$4.4 million to ~~$15.9~~$18.0 million in the three months ended ~~September 30, 2010,~~March 31, 2011, from ~~$10.5~~$13.6 million in the three months ended ~~September 30, 2009. The~~March 31, 2010. A significant portion of this increase was ~~primarily~~ the result of our salaries and benefits ~~amount~~expense increasing by ~~$2.0~~$2.7 million between periods as we increased our employee headcount from ~~158~~267 at ~~September 30, 2009~~March 31, 2010 to ~~622~~747 (including the addition of ~~351~~447 and 8021 IMW and ~~BAF~~Northstar employees, respectively) at ~~September 30,~~March 31, 2011. We also experienced a $1.4 million increase in occupancy costs, business insurance, contract labor, information technology maintenance, training and seminars and office supplies expenses related to our continued business growth and our acquisitions of IMW and Northstar during the third and fourth quarters of 2010. ~~Our~~In addition, our professional fees increased ~~$0.8~~$0.6 million between periods, primarily for legal, audit and consulting services related to our ~~acquisition of the IMW Acquired Business. In addition, our~~continued business growth. Our travel and entertainment expenses increased ~~$0.4~~$0.3 million between periods, primarily due to the increased travel of our sales team. ~~Our marketing expenses increased $0.4 million~~Stock option expense between periods increased $0.3 million due to ~~certain advertising we conducted related~~the stock options issued in 2010 to ~~the Ports of Los Angeles and Long Beach.~~new employees. We also experienced a ~~$0.8~~$0.1 million increase in ~~business insurance, contract labor, software/hardware maintenance, training/seminars~~research and ~~office supplies~~development costs between periods related to our ~~continued business growth. Our bad debt expense increased $1.4 million due to a reversal of our~~ BAF ~~loan provision in the third quarter of 2009.~~operation. Offsetting these increases was a decrease of ~~$0.5~~$1.0 million during the ~~third~~first quarter of ~~2010~~2011 related to a decrease in the IMW and BAF contingent consideration ~~liability and a decrease of $0.3 million between periods related to our stock-based compensation expense.~~liabilities.

Depreciation and amortization. Depreciation and amortization increased by ~~$1.0~~$2.2 million to ~~$5.5~~$7.2 million in the three months ended ~~September 30, 2010,~~March 31, 2011, from ~~$4.5~~$5.0 million in the three months ended ~~September 30, 2009.~~March 31, 2010. This increase was primarily due to additional depreciation expense in the three months ended September 30, 2010 related to increased property and equipment balances between periods, including our expanded station network. Our September 30, 2010 amortization expense includes increased amortization of the intangible assets we obtained in connection with our BAF acquisition in the fourth quarter of 2009 and the acquisition of the IMW Acquired Business on September 7, 2010.

~~Derivative (gain) loss on Series I warrant valuation.~~ Derivative (gain) loss decreased by $23.3 million to a gain of $7.9 million in the three months ended September 30, 2010, from a loss of $15.4 million in the three months ended September 30, 2009. The decrease represents the decreased fair market value of our outstanding Series I warrants based on our mark-to-market accounting on our Series I warrants (see notes 18 and 19 to our condensed consolidated financial statements contained elsewhere herein) during the three month period ended September 30, 2010.

~~Interest income (expense), net.~~ Interest income (expense), net, decreased by $0.2 million from $0.3 million in the three months ended September 30, 2009, to $0.1 million in the three months ended September 30, 2010. This decrease was primarily the result of a decrease in interest expense, net of amounts capitalized, in the three months ended September 30, 2010 as we repaid in full our Facility A Loan on October 7, 2009 (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 $0.3 million of expense for three months ended September 30, 2010. This increase was primarily related to foreign currency exchange losses of the IMW Acquired Business in the three months ended September 30, 2010 that did not occur in the three months ended September 30, 2009.

~~Income from equity method investments.~~ ~~There was no significant change in income from equity method investments between the three months ended September 30, 2010 and the three months ended September 30, 2009.~~

~~Loss (income) attributable to noncontrolling interest.~~ Loss (income) attributable to noncontrolling interest was $80,000 for the noncontrolling interest in the net income of DCE in the three months ended September 30, 2009, as compared to $94,000 for the noncontrolling interest in the net loss of DCE in the three months ended September 30, 2010. The noncontrolling interest represents the 30% interest of our joint venture partner.

~~Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009~~

~~Revenue.~~ Revenue increased by $39.4 million to $128.7 million in the nine months ended September 30, 2010, from $89.3 million in the nine months ended September 30, 2009. A portion of this increase was the result of an increase in the number of gallons delivered from 71.5 million gasoline gallon equivalents to 91.0 million gasoline gallon equivalents. The increase in volume was partly from an increase in CNG sales of 11.7 million gallons and an increase in biomethane sales (our 70% share of the biomethane sales of DCE) of 1.3 million gallons. The acquisition of four compressed natural gas operations and maintenance services contracts in May and June of 2009, four new refuse customers, and one new regional trucking customer together accounted for 9.6 million gallons of the CNG volume increase. The volume growth from our existing public and refuse customers, combined with the volume growth from our share of our joint venture in Peru, contributed to the remaining CNG volume increase. We also experienced an increase of 6.5 million gallons in LNG volume between periods, which was primarily due to the volume growth of 2.5 million gallons from our existing transit and refuse customers, combined with a 3.1 million gallon increase from our port trucking customers. We also had LNG volume increases of 0.9 million gallons from two new refuse customers and one new regional trucking customer. Revenue also increased by $29.3 million between periods from sales of natural gas vehicle equipment by BAF, which we acquired on October 1, 2009. Our acquisition of the IMW Acquired Business on September 7, 2010 contributed $3.3 million to our increased revenue between periods. Our effective price per gallon was consistent between periods at $1.01. Offsetting our revenue increases was a decrease in our fuel tax revenues between periods as the fuel tax credits expired on DecemberMarch 31, 2009. We did not record any fuel tax revenues in the first nine months of 2010, and we recorded $11.8 million of revenue related to fuel tax credits in the first nine months of 2009. We also experienced a $1.1 million decrease in station construction revenues between periods.

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~~Cost of sales.~~ Cost of sales increased by $35.1 million to $91.7 million in the nine months ended September 30, 2010, from $56.6 million in the nine months ended September 30, 2009. Our cost of sales primarily increased between periods as a result of delivering more volume to our customers together with $21.0 million of increased costs related to BAF’s vehicle equipment sales, which we began to recognize on October 1, 2009 when we acquired the company. We also recognized $2.4 million of costs from sales of compressor equipments and services by the IMW Acquired Business, which we began to recognize on September 7, 2010 when we acquired the IMW Acquired Business. These increases were offset by the decrease in our effective cost per gallon of $0.02 per gallon, to $0.71 per gallon, in the nine months ended September 30, 2010. We also experienced a $0.9 million decrease in station construction costs between periods.

~~Selling, general and administrative.~~ Selling, general and administrative expenses increased by $10.8 million to $44.4 million in the nine months ended September 30, 2010, from $33.6 million in the nine months ended September 30, 2009. A significant portion of this increase was the result of our salaries and benefits amount increasing by $5.0 million between periods as we increased our employee headcount from 158 at September 30, 2009 to 622 (including the addition of 351 and 80 IMW and BAF employees, respectively) at September 30, 2010. We also experienced a $2.4 million increase in business insurance, contract labor, software/hardware maintenance, training/seminars and office supplies related to our continued business growth. Our travel and entertainment expenses increased $1.1 million between periods, primarily due to increased travel of our sales team. In addition, our professional fees increased $1.5 million between periods, primarily for legal, audit and consulting services related to the acquisition of the IMW Acquired Business. Our bad debt expense increased $1.4 million due to a reversal of our BAF loan provision in the third quarter of 2009. Our marketing expenses increased $0.6 million between periods due to certain advertising we conducted related to the Ports of Los Angeles and Long Beach.

~~Depreciation and amortization.~~ Depreciation and amortization increased by $3.3 million to $15.6 million in the nine months ended September 30, 2010, from $12.3 million in the nine months ended September 30, 2009. This increase was due to additional depreciation expense in the nine months ended September 30, 20102011 related to increased property and equipment balances between periods, primarily related to our expanded station network. Our ~~September 30, 2010~~March 31, 2011 amortization expense also includes increased amortization of the intangible assets we obtained in connection with our acquisition of IMW in the ~~operation and maintenance contracts we acquired during the second~~third quarter of ~~2009, BAF~~2010, and Northstar in the fourth quarter of ~~2009 and the acquisition of the IMW Acquired Business on September 7,~~ 2010.

Derivative ~~gain (loss)~~(gain) loss on Series I warrant valuation. Derivative ~~(gain)~~ loss decreased by ~~$23.7~~$15.3 million to ~~a gain of $5.9~~$3.3 million in the ~~nine~~three months ended ~~September 30, 2010,~~March 31, 2011, from ~~a loss of $17.8~~$18.6 million in the ~~nine~~three months ended ~~September 30, 2009.~~March 31, 2010. The ~~decrease represents~~amounts represent the ~~decreased~~ non-cash ~~charge we took~~impact with respect to valuing our outstanding Series I warrants based on our mark-to-market accounting for the warrants (see ~~notes 18 and 19~~note 17 to our condensed consolidated financial statements contained elsewhere herein) during the ~~nine~~three month period ended ~~September 30, 2010.~~March 31, 2011.

Interest income (expense), net. Interest income (expense), net, increased by ~~$384,000 from $368,000~~$0.9 million to $0.8 million of expense for the ~~nine~~three months ended ~~September 30, 2009, to $16,000 of income for the nine months ended September 30, 2010.~~March 31, 2011. This increase was primarily the result of ~~a decrease~~an increase in interest expense ~~net of amounts capitalized,~~ in the ~~first nine~~three months ended March 31, 2011 related to debt we incurred in connection with the acquisition of ~~2010 as we repaid in full our Facility A Loan on October 7, 2009 (see note 11 to our condensed consolidated financial statements contained elsewhere herein).~~IMW.

Other income (expense), net. ~~There was no significant change in other~~Other income (expense), net, ~~between the nine months ended September 30, 2010 and the nine months ended September 30, 2009.~~

~~Income from equity method investments.~~ ~~Income from equity method investments~~ increased ~~$71,000~~by $0.6 million to ~~$201,000~~$0.6 million of income for the ~~nine~~three months ended ~~September 30, 2010 related to our share of our joint venture in Peru.~~

~~Loss (income) attributable to noncontrolling interest.~~ ~~During~~March 31, 2011, from $0.0 million for the ~~nine~~three months ended ~~September 30, 2010,~~March 31, 2010. This increase was primarily due to the impact of foreign currency exchange gains on the notes we ~~recorded $27,000 for~~issued as part of the noncontrolling interest in the net loss of DCE, compared to $431,000 for the noncontrolling interest in the net loss of DCE in the nine months ended September 30, 2009. The noncontrolling interest represents the 30% interest of our joint venture partner.IMW acquisition.

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Income from equity method investment. During the first quarter of 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 March 31, 2010, we recorded income of $0.1 million related to our interest.

Income (loss) of noncontrolling interest. During the three months ended March 31, 2011, we recorded $0.3 million for the noncontrolling interest in the net income compared to $0.0 million for the noncontrolling interest in the net loss of DCE for the three months ended March 31, 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. ~~In May 2007, we completed~~From and including our initial public offering in May 2007, we have raised a cumulative net amount of ~~10,000,000 shares~~equity financing of ~~common stock at~~approximately $273.6 million. In addition, T. Boone Pickens, our largest shareholder, holds a public offering price of $12.00 per share. Net cash proceeds from the initial public offering were approximately $108.5 million, after deducting underwriting discounts, commissions and offering expenses. On August 15, 2008, in connection with our acquisition of 70% of the membership interests of DCE, we entered into a credit agreement with PCB pursuantwarrant to which we borrowed $18.0 million under a term loan and an additional $12.0 million under a line of credit (see note 10 to the accompanying condensed consolidated financial statements). On September 24, 2008, we sold 319,488purchase 15,000,000 shares of our common stock at $10 per share that expires on December 28, 2011. We have included a proposal in our 2011 proxy statement to amend the warrant to incentivize Mr. Pickens to exercise all or a portion of the warrant prior to December 28, 2011; however, this proposal is subject to the approval of our shareholders. Also, we had 2,130,682 Series I warrants outstanding as of March 31, 2011, with a current exercise price of ~~$15.65~~$12.68 per share to Boone Pickens Interests, Ltd. for proceeds of approximately $5.0 million. On November 3, 2008, we sold 4,419,192 units of common stock and warrants for $7.92 per unit and we raised net proceeds of approximately $32.5 million after deducting offering costs. On July 1, 2009, we sold 9,430,000 shares of our common stock to third party investors and received net proceeds of $73.2 million. On October 7, 2009, we repaid the $18.0 million term loan with PCB and simultaneously amended the Credit Agreement to obtainshare.

We currently have a $20 million line of credit (“LOC”) from ~~PCB. The $20 million LOC~~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 ~~PCB debt facilities.~~covenants contained in the Credit Agreement. As of ~~September 30, 2010,~~March 31, 2011, we did not have ~~not drawn~~ any ~~loan amounts~~balance outstanding under the ~~new LOC and we~~LOC. As of March 31, 2011, IMW had an outstanding balance of ~~$9.9~~$7.8 million ~~on our Facility B Loan. As of September 30, 2010, the Acquisition Subsidiary had an outstanding balance of $6.8 million~~due under the IMW Lines of ~~Credit. The Acquisition Subsidiary~~ ~~also issued the following promissory notes to IMW (collectively, the “IMW Notes”): (i)~~Credit and we owed a ~~promissory note with a principal amount~~balance of $12,500,000 that is due and payable on January 31, 2011, (ii) a promissory note with a principal amount of $12,500,000 that is due and payable on January 31, 2012, (iii) a promissory note with a principal amount of $12,500,000 that is due and payable on January 31, 2013, and (iv) a promissory note with a principal amount of $12,500,000 that is due and payable on January 31, 2014. Each payment$33.1 million under the IMW Notes ~~will consist~~due to IMW’s former owner. DCEMB has approximately $27.1 million available to expand and operate the landfill gas processing facility it owns at the McCommas Bluff Landfill outside Dallas, Texas after competing its bond offering on March 31, 2011.

Our credit agreement with PCB requires that we comply with certain covenants, as detailed in footnote 11 of ~~$5.0 million in cash and $7.5 million in cash and/or shares~~our condensed consolidated financial statements contained elsewhere herein. One of the ~~Company’s common stock (the exact combination~~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 are required to maintain a debt service ratio, as defined, of ~~cash and/or common stock~~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 ~~determined at~~applied to the ~~Acquisition Subsidiary’s option).~~balance due on the PCB loans. We also ~~issued 4,017,408 shares~~would be unable to use the $20 million PCB line of ~~our common stock~~credit if this were to ~~IMW’s shareholder.~~occur. We were in compliance with all of the covenants as of March 31, 2011.

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. On August 31, 2010, we executed a non-binding letter of intent to acquire all of the outstanding interests or substantially all of the assets of Northstar for consideration of up to $16 million, with $6.5 million payable at closing, and a portion of the consideration to be allocated to employee retention programs. The remaining consideration will be paid in equal installments over the five years following the closing. This acquisition is subject to board approval, completion of due diligence, and execution of a definitive purchase agreement. We financed our operations in the first ~~nine~~three months of ~~2010~~2011 primarily through cash on hand, cash provided by operating activities and cash provided by financing activities.

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At ~~September 30, 2010,~~March 31, 2011, we had total cash and cash equivalents of ~~$32.2~~$51.9 million, compared to ~~$67.1~~$55.2 million at December 31, ~~2009.~~2010.

Cash provided by operating activities was ~~$11.8~~$9.9 million for the ~~nine~~three months ended ~~September 30, 2010,~~March 31, 2011, compared to ~~$10.4~~cash used in operating activities of $1.0 million for the ~~nine~~three months ended ~~September 30, 2009.~~March 31, 2010. The increase in operating cash flow resulted primarily from the cash received during the first quarter of 2011 related to the volumetric excise tax credit of approximately $16.0 million, which was offset by changes in working capital balances due to timing differences related to various cash flows between periods. Our operating cash flow, before working capital changes, decreased between periods, mostly due to the loss of fuel tax revenues in the first nine months of 2010 as the legislation providing for the tax rebates expired December 31, 2009. We recorded $11.8 million of fuel tax revenues in the first nine months of 2009.

Cash used in investing activities was ~~$57.1~~$40.6 million for the ~~nine~~three months ended ~~September 30, 2010,~~March 31, 2011, compared to ~~$32.2~~$8.8 million for the ~~nine~~three months ended ~~September 30, 2009.~~March 31, 2010. Our purchases of property and equipment were ~~$41.4~~$10.8 million during the first ~~nine~~three months of ~~2010, compared to $25.4~~2011, and $8.8 million ~~for~~during the ~~same period in 2009. In May and June 2009, we acquired four compressed natural gas operations and maintenance service contracts for $5.6 million.~~first three months of 2010. We made an additional ~~investment~~investments during the first three 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 ~~nine~~three months of ~~2009 of $4.2 million, compared to $0.4~~2010. We invested $1.2 million for a 19.9% interest in ServoTech Engineering, Inc. (“ServoTech”), a company who provides design and engineering services for natural gas fueling systems, among other services, during the ~~same period in 2010. In September 2010, we invested $15.6 million in initial payments related to~~three months ended March 31, 2011. Also during the ~~acquisition~~first quarter of 2011, as part of the ~~IMW Acquired Business.~~

~~Table~~DCEMB bond offering, we placed $27.1 million of ~~Contents~~cash into restricted accounts to be used for the capital and operating expenses of DCEMB.

Cash provided by financing activities for the ~~nine~~three months ended ~~September 30,~~March 31, 2010 was ~~$10.3~~$28.3 million, compared to ~~$77.8~~$9.0 million for the ~~nine~~three months ended ~~September 30, 2009. The decrease was~~March 31, 2010. This increase is primarily ~~related~~due to the ~~July 2009 common stock~~DCEMB bond offering of $40.2 million for the use in the expansion of the landfill gas processing facility owned by DCEMB that closed on March 31, 2011. Additionally, we received net proceeds from ~~which~~borrowings under our HSBC line of credit of $2.9 million to finance the working capital needs at IMW. These proceeds were offset by cash paid of $9.9 million on March 31, 2011 to pay off our Facility B Loan, and the cash payment of $5.0 million as part of the first IMW Note payment owed as part of the acquisition of IMW. Additionally we received net proceeds of ~~$73.2~~$0.4 million ~~and additional bank borrowings~~from the exercise of employee stock options in the ~~first nine~~three months ~~of 2009 of $7.2~~ended March 31, 2011 compared to $9.2 million ~~from PCB to fund capital expenditures related to DCE’s landfill plant upgrade. Offsetting~~for the ~~decrease was current year stock option exercises, from which we received net proceeds of approximately $10.8 million.~~three months ended March 31, 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, ~~DCE~~biomethane plant construction costs and the purchase of LNG tanker trailers and equipment) and any merger or acquisition activity.

Capital Expenditures

Our ~~current~~ business plan calls for approximately ~~$17.1~~$70.7 million in ~~additional~~ capital expenditures from ~~October~~April 1, ~~2010~~2011 through the end of ~~2010,~~2011, primarily related to construction of new fueling stations. This amount excludes 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 $6.5 million~~elect to ~~fund the closing~~invest additional amounts in expansion of our ~~acquisition of Northstar if we are successful~~California LNG plant or for other acquisitions or investments in ~~completing~~companies or assets in the ~~acquisition in 2010.~~natural gas fueling infrastructure, services and production industries, including biomethane production. We ~~anticipate that we~~ will need to raise additional capital ~~to continue~~as necessary to fund any of the ~~growth~~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 ~~business. If we have significant unanticipated~~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 ~~expenditures, investments, acquisitions~~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 ~~operating expenses, we may also seek to raise capital to fund such capital expenditures, investments, acquisitions or expenses.~~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 ~~invest in our biomethane business,~~ and invest in strategic transactions or acquisitions, and reduce the ability of our ~~ability~~business to grow and generate increased revenues.

~~Contractual Obligations~~30

~~The following represents the scheduled maturities of our contractual obligations as of September 30, 2010:~~

Payments Due by Period

Contractual Obligations:

Total

Remainder of
2010

2011 and 2012

2013 through 2015

2016 and beyond

Debt and capital lease obligations(a)

$
69,362,439

$
7,365,134

$
32,760,521

$
29,236,784

$
0

Operating lease commitments(b)

23,658,220

857,510

6,148,529

9,135,393

7,516,788

“Take or pay” LNG purchase contracts(c)

23,160,094

1,263,356

7,114,350

9,175,275

5,607,113

Construction contracts(d)

17,246,326

12,888,778

4,357,548

0

0

Total

$
133,427,079

$
22,374,778

$
50,380,948

$
47,547,452

$
13,123,901

~~(a)Consists~~Table of ~~debt (including the IMW Notes) and capital lease obligations to finance equipment purchases, including implied interest.~~

~~(b)Consists of various space and ground leases for our California LNG plant, offices and fueling stations as well as leases for equipment.~~

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

~~(d)~~Consists of our obligations to fund various fueling station construction projects, net of amounts funded through September 30, 2010, and excluding contractual commitments related to station sales contracts.Contents

Off-Balance Sheet Arrangements

At ~~September 30, 2010,~~March 31, 2011, we had the following off-balance sheet arrangements that had, or are reasonably likely to have, a material effect on our financial ~~condition.~~condition:

· outstanding surety bonds for construction contracts and general corporate purposes totaling ~~$21.7~~$37.3 million,

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· two take-or-pay ~~contract~~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 2011 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 ~~$230,000~~$0.2 million per year, plus up to ~~$130,000~~$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. ~~Commercial operations began December 1, 2008, and the payments for this lease are included in “Operating lease commitments” in the “Contractual Obligations” table set forth above.~~

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

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 ~~through~~ 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.

Natural gas costs represented ~~42%~~30% (or ~~44 %~~33% excluding ~~BAF)~~BAF, IMW and Northstar) of our cost of sales for ~~fiscal year ending 2009~~2010 and ~~35%~~24% (or ~~47%~~44% excluding BAF, IMW and ~~the IMW Acquired Business)~~Northstar) of our cost of sales for ~~the nine month~~three months ended ~~September 30, 2010.~~March 31, 2011. Prices for natural gas over the ~~ten-year~~eleven-year and ~~nine-month~~three month period from December 31, 1999 through ~~September 30, 2010,~~March 31, 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 ~~September 30, 2010,~~March 31, 2011, the NYMEX index price of natural gas was ~~$3.64~~$3.79 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 ~~the accounting~~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. Our futures contracts did not qualify for hedge accounting under this guidance for the years ended December 31, 2005 and 2006, and we did not have any derivative activity in 2007. Consequently, any changes in the fair value of the derivatives during 2005 and 2006 were recorded directly to our consolidated statements of operations. In 2008, we had certain contracts that did not qualify for hedge accounting and we had two derivative contracts to hedge two fixed supply contracts that did qualify for hedge accounting. During 2009 and the nine month period ended September 30, 2010, we had five futures contracts that did qualify for hedge accounting.

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The fair value of the futures contracts we use is based on quoted prices in active exchange traded or over the counter markets 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, ~~in February 2007,~~ our board of directors adopted a revised natural gas hedging policy which restricts

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our ability to purchase natural gas futures contracts and offer fixed price sales contracts to our customers. ~~This policy was further revised by our board of directors in May 2008.~~ We plan to structure prospective futures contracts so that they will be accounted for as cash flow hedges under this guidance, but we cannot be certain they will qualify. For more information, please read ~~“—Risk~~“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 ~~September 30, 2010~~March 31, 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 ~~September 30, 2010~~March 31, 2011 ($~~3.64~~3.79 per Mcf), we could expect a corresponding fluctuation in the value of the contracts of approximately ~~$0.9~~$0.7 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 $0.6 million of gains in the three months ended March 31, 2011. During the three months ended March 31, 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 March 31, 2011, we would expect a corresponding fluctuation in the value of the assets and liabilities of approximately $1.6 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

On September 7, 2010, the Company purchased the IMW Acquired Business. In the third quarter, the Company began to integrate the acquisition into its internal control over financial reporting structure. As such, there have been changes during the quarter associated with the establishmentWe regularly review our system of internal control over financial reporting ~~with respect~~and make changes to ~~the IMW Acquired Business.~~ 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.

There were no ~~other~~ 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 ~~may become~~are party to various legal actions that ~~arise~~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. On July 15, 2010, we received a letter from the IRS disallowing approximately $5.1 million related to certain claims we filed from October 1, 2006 through June 30, 2008 under the Volumetric Excise Tax Credit program. We believe our claims were properly made and has appealed the IRS’s request for payment. 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 ifof these liabilities, if any. If these matters were to be ultimately resolved unfavorably, an outcome not currently anticipated, it is possible that such outcome could have a material adverse effect upon our consolidated financial position or results of operations. However, we believe that the ultimate resolution of such actions will not have a material adverse ~~affect~~effect on our consolidated financial position, results of operations, or liquidity.

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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.

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 ~~together with the risk factors in Part I, Item 1A of our 2009 Annual Report on Form 10-K~~ 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.

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

For the ~~nine~~three month period ended ~~September 30, 2010,~~March 31, 2011, we incurred pre-tax losses of ~~$17.2~~$10.2 million, which included a derivative ~~gain~~losses of ~~$5.9~~$3.3 million related to marking to market the value of our Series I warrants. During the three months period ended March 31, 2011, our loss was decreased by our receipt of approximately $4.2 million of revenue from federal fuel tax credits. In ~~2007,~~ 2008, 2009 and ~~2009~~2010, we incurred pre-tax losses of ~~$7.7 million,~~ $44.3 million, $33.4 million, and ~~$33.4~~$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 and~~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 ~~2007,~~ 2008, 2009 and ~~2009,~~2010, our losses were substantially decreased by our receipt of approximately ~~$17.0 million,~~ $17.2 million, $15.5 million and ~~$15.5~~$16.0 million of revenue from federal fuel tax ~~credits; however, the law providing for the fuel tax~~ credits, ~~expired on December 31, 2009.~~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 ~~expired~~expires on December 31, ~~2009.~~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, ~~expired~~expires December 31, ~~2009.~~2011. Based on the service relationship we ~~had~~have with our customers, either we or our customers ~~were~~are able to claim the credit. ~~In 2007, 2008 and 2009,~~For the three month period ended March 31, 2011, we recorded approximately ~~$17.0~~$4.2 million related to fuel tax credits, representing approximately 6.5% of our total revenue. In 2008, 2009 and 2010, we recorded approximately $17.2 million, $15.5 million and ~~$15.5~~$16.0 million of revenue, respectively, related to fuel tax credits, representing approximately ~~14.5%~~13.7%, ~~13.7%~~11.8% and ~~11.8%~~7.6%, respectively, of our total revenue during the periods. If the fuel tax credit is not reinstated during 2010 or extended to future periods, our revenue during 2010 and any such future periods will be materially reduced and our financial performance will suffer. Analysts that write research on our company may also reduce their ratings or make negative adjustments to their future expectations of our financial performance if the fuel excise tax credit is not reinstated or extended to future periods, which may also result in a decrease in the price of our common stock. In addition, onOn 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 and ~~we may have to~~potentially revise or restate ~~our~~ historical financial ~~statements for some or all of the time period from October 1, 2006 through June 30, 2008 to account for~~results based on the reduction in revenue.

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. Our business plan calls for approximately ~~$17.1~~$70.7 million in capital expenditures from ~~October~~April 1, ~~2010~~2011 through ~~December~~the end of 2011. This amount excludes the capital expenditures DCEMB will make at its landfill gas processing facility with the proceeds it received on March 31, ~~2010.~~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 ~~the~~ IMW ~~Acquired Business.~~

~~On September 7, 2010, the Company, acting through certain of its subsidiaries, completed its purchase of the advanced, non-lubricated natural gas fueling compressor~~ and ~~related equipment manufacturing~~Northstar. At May 9, 2011, our future payments for IMW and servicing business (the “IMW Acquired Business”) of I.M.W. Industries Ltd., a British Columbia corporation (“IMW”). A subsidiary of the Company (the “Acquisition Subsidiary”) paid an upfront cash payment of approximately $15.6Northstar totaled $37.5 million (subject to a final working capital adjustment) and issued 4,017,408 shares of the Company’s common stock at closing to IMW’s shareholder. In connection with the closing of the Company’s acquisition of the IMW Acquired Business, the Acquisition Subsidiary also issued the following promissory notes to IMW (collectively, the “IMW Notes”): (i) a promissory note with a principal amount of $12,500,000 that is due and payable on January 31, 2011, (ii) a promissory note with a principal amount of $12,500,000 that is due and payable on January 31, 2012, (iii) a promissory note with a principal amount of $12,500,000 that is due and payable on January 31, 2013, and (iv) a promissory note with a principal amount of $12,500,000 that is due and payable on January 31, 2014. Each payment under the IMW Notes will consist of $5.0 million in cash and $7.5 million, ~~in cash and/or shares~~respectively. Also, at March 31, 2011, we were obligated to pay up to $40.0 million as additional consideration related to our IMW acquisition if certain performance measurements of ~~the Company’s common stock (the exact combination~~IMW are met and up to $11.0 million as additional consideration related to our BAF acquisition if certain performance measurements of ~~cash and/or stock to be determined at the Acquisition Subsidiary’s option). In addition, pursuant to a security agreement executed at closing, the IMW Notes~~BAF are ~~secured by a subordinate security interest in the IMW Acquired Business.~~met.

~~On August 31, 2010, we executed a non-binding letter~~33

Table of intent to acquire all the outstanding interests or substantially all the assets of Northstar for consideration of up to $16 million, with $6.5 million payable at closing, and a portion of the consideration to be allocated to employee retention programs. The remaining consideration will be paid in equal installments over the five years following the closing. This acquisition is subject to Board approval, completion of due diligence, and execution of a definitive purchase agreement.Contents

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 ~~and rapidly falling prices~~ in the equity capital markets have ~~severely and~~ adversely affected capital raising opportunities. If we are unable to obtain debt or equity financing in amounts sufficient to fund 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 could harm our business, results of operations, and future prospects.

~~Table~~T. Boone Pickens, our largest shareholder, holds a warrant to purchase 15,000,000 shares of ~~Contents~~our common stock at $10 per share that expires on December 28, 2011. We have included a proposal in our 2011 proxy statement to amend the warrant to incentivize Mr. Pickens to exercise a portion of the warrant prior to December 28, 2011; however this proposal is subject to the approval of the Company’s shareholders. To the extent this warrant is exercised as a whole or in part, we would receive cash proceeds. However, our shareholders may not approve the warrant amendment and there can be no assurances that the warrant will be exercised in any part.

Our growth ~~depends in part on~~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 ~~will significantly~~may reduce our revenue.

Our business ~~depends in part on~~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 ~~fuel excise tax credit for the sale of natural gas fuel expired on December 31, 2009. The federal~~ income tax credit that iswas available to offset 50% to 80% of the incremental cost of purchasing new or converted natural gas vehicles ~~is scheduled to expire~~expired on December 31, ~~2010, and if~~2010. The absence of these vehicle tax credits ~~are not extended, it will~~could have a detrimental effect on the natural gas vehicle and fueling industry, including sales at our wholly owned ~~subsidiaries,~~subsidiary, BAF, ~~and the IMW Acquired Business,~~ 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 ~~reinstatement and~~ 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 ~~and~~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.

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.

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Automobile and engine manufacturers 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 makes natural gas powered passenger vehicles, and major manufacturers of medium and heavy duty vehicles 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, or additional heavy-duty truck engine manufacturers do not enter the market for LNG engines, it may delay, impair, or eliminate the growth of our LNG fueling business, which would impair 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.

Decreases in the price of oil, gasoline and diesel fuel ~~without similar decreases in the price of natural gas~~ may slow the growth of our business and negatively impact our financial results.

~~Prices~~Recent increases in prices for oil, gasoline and diesel fuel have declined substantially from the recent high prices reached in the summer of 2008. The price of a barrel of crude oil has declined from a high of $148.35 per barrel reached on July 11, 2008 to a price of $79.97 per barrel on September 30, 2010. Average retail prices for ultra low sulfur diesel fuel in California have declined from a high of $5.03 in May and June 2008 to $3.14 per gallon at September 30, 2010, and average retail prices for gasoline in California have declined from a high of $4.59 per gallon in June 2008 to $3.04 per gallon at September 30, 2010. The decrease in the price of diesel and gasoline, in particular, has resulted in ~~reduced~~increased interest in alternative fuels such as ~~LNG~~CNG and ~~CNG.~~LNG. However, any decline in the price of oil, diesel fuel and gasoline may result in reduced interest in CNG and LNG. Decreased interest in alternative fuels ~~will~~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. Our retail prices for LNG fuel in California decreased from $3.70 per diesel gallon equivalent in June and July of 2008 to $2.20 per diesel gallon equivalent at September 30, 2010, and our retail prices for CNG fuel sold in the Los Angeles basin decreased from a high of $3.30 per gasoline gallon equivalent in July of 2008 to $2.50 per gasoline gallon equivalent at September 30, 2010. LowerFurther, lower fuel prices for CNG and LNG as a result of lower natural gas commodity prices also will reduce our revenues.

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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 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, ~~and continuing uncertainty about fuel prices,~~ 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 ~~September 30,~~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. ~~As of September 30, 2010,~~At March 31, 2011, the NYMEX index price for natural gas was ~~$3.64~~$3.79 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 on 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.~~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

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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 ~~change~~changes in regulations that ~~makes~~make it ~~substantially~~ 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. In particular, the Ports of Los Angeles and Long Beach have adopted the San Pedro Bay Ports Clean Air Action Plan, which outlines a Clean Trucks Program that calls for the replacement of drayage trucks with trucks that meet certain clean truck standards. Industry participants with a vested interest in gasoline and diesel, many of which have substantially greater resources than we do, invest significant time and money in an effort to influence environmental regulations in ways that delay or repeal requirements for cleaner vehicle emissions. Further, an economic ~~recession~~difficulties may result in the delay, amendment or waiver of environmental regulations ~~or the Clean Trucks Program~~ 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 commenced in the State of California and ~~political support for~~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.

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CNG, LNG and biomethane vehicle fuel all produce fewer greenhouse gases 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 ~~and in particular the Clean Trucks Program outlined in the San Pedro Bay Ports Clean Air Action Plan or California’s AB 32,~~ 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, ~~and~~ our ability to supply CNG and LNG at competitive ~~prices. The~~prices and acceptance of our technology, fuel systems or services. A decline in oil, diesel fuel and gasoline prices ~~from the levels they reached during the summer of 2008 has resulted~~may result in decreased interest in alternative fuels like CNG and LNG. In addition, ~~the disruption in the capital markets that began in 2008 has~~there is reduced ~~the~~ availability of 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;

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·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 ~~cannot be certain that we will~~may not be successful in managing or integrating ~~our recently acquired subsidiary, BAF, with our existing operations.~~

On October 1, 2009, we closed our acquisition of 100% of the equity interests of BAF, which is now our wholly owned subsidiary. BAF provides natural gas vehicle conversions, alternative fuel systems, application engineering, service and warranty support and research and development services. Historically, BAF has suffered net operating losses and required outside financing to support its ongoing business. Our ability to realize benefits from the acquisition depends on our ability to improve BAF’s financial performance in comparison to its historical financial results. Our management team has limited experience managing a vehicle conversion company, and BAF represents a new product offering for our company. The successful management and integration of BAF’s operations will present significant challenges, including realizing economies of scale and integrating internal financial and operational systems. We cannot provide any assurances that we will realize any anticipated benefits or will successfully integrate any of the acquired operations with our existing operations. In addition, the BAF 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 BAF operations, we cannot provide assurance as to the effectiveness of BAF’s disclosure controls and procedures or internal controls over financial reporting until we have fully integrated them.

~~A significant portion of the purchase price of the IMW Acquired Business 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 the IMW Acquired Business to its net tangible assets 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. Management’s estimates of the fair value of the assets and liabilities of the IMW Acquired Business 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 $44.2 million of the purchase price for the IMW Acquired Business to goodwill. Our goodwill could be impaired if developments affecting the acquired compressor manufacturing operations or the markets in which the IMW Acquired Business 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 cannot be certain that we will be successful in managing or integrating the acquired business of~~ 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 ~~the~~ IMW ~~Acquired Business~~ 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

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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 successfully integrate ~~the~~ IMW ~~Acquired Business~~ 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 ~~the~~ IMW ~~Acquired Business~~ 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 ~~the~~ IMW ~~Acquired Business~~ 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 ~~the~~ IMW, ~~Acquired Business,~~ we cannot provide assurance as to the effectiveness of the disclosure controls and procedures or internal controls over financial reporting of ~~the~~ IMW ~~Acquired Business~~ until we have fully integrated them.

~~Failure~~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.

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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 ~~our Credit Agreement with PlainsCapital Bank could~~its bond financing agreements would impair our rights in ~~DCE and other secured property.~~DCEMB.

In ~~August 2008, we acquired a 70% interest in DCE, which manages a biomethane production facility at~~connection with the ~~McCommas Bluff landfill in Dallas, Texas,~~Issuance of the Revenue Bonds, DCEMB entered into, among other documents, the Loan Agreement, the Note, the Deed of Trust and ~~holds a lease~~the Security Agreement (collectively the “Bond Agreements”). Pursuant to the ~~associated landfill gas development rights. We borrowed $18 million from PCB~~Bond Agreements, DCEMB is subject to ~~fund~~certain covenants, including a requirement to make loan repayments on the ~~acquisition and obtained a $12 million line of credit from PCB to pay certain costs and expenses of the acquisition and finance capital improvements of the gas processing plant through a loan made~~Revenue Bonds. This repayment obligation is secured by us to DCE. We have used $12.0 million of the line of credit from PCB, and the outstanding balance was $9.9 million as of September 30, 2010. In October 2009, we repaid the $18 million loan that we used to fund the acquisition of DCE and amended the Credit Agreement to obtain a $20 million line of credit from PCB to finance capital expenditures and working capital for our operations, and for other general business purposes. During the nine months ended September 30, 2010, we did not borrow any money under the $20 million line of credit. To secure our obligations under the Credit Agreement, we granted PCB a security interest in 45 of our LNG tanker trailers, certain accounts receivable and inventory, and our note receivable from, and our membership interests in, DCE. Our Credit Agreement with PCB requires that we comply with certain covenants. One of the covenants requires that we maintain accounts receivable balances from certain subsidiaries above $8 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 ended June 30, 2009, we have been required to maintain a specific minimum debt service ratio. 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 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 ~~Credit Agreement will become immediately due and payable and $2.5 million of~~Bond Agreements, our ~~funds held by PCB~~rights in DCEMB would be ~~applied to the balance due on the PCB loans. We also would~~impaired, and our business and results of operations may be ~~unable to use the $20 million PCB line of credit if this were to occur.~~

For the quarter ended September 30, 2010, we were not in compliance with our debt service ratio covenant under the Credit Agreement, however, PCB agreed to waive compliance with this covenant until the next quarterly calculation at December 31, 2010.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 ~~and continued~~or disruption in the capital markets may make it difficult or impossible to obtain 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.

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 ~~LNG~~CNG and ~~CNG~~LNG station construction, maintenance and fuel sales contracts with various federal, state and local governmental bodies, which accounted for approximately ~~64%~~68% of our ~~yearly~~annual revenues ~~from~~in 2006 ~~through 2009.~~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.

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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. ~~Our contracts with governmental entities constituted approximately 64% of our revenues from 2006 to 2009.~~ 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. Since we compete for several of our contracts with government entities through a competitive bidding process, in order to be awarded new contracts or for the renewal of an expired contract, we may have to agree to lower prices for CNG fuel, LNG fuel and our operations and maintenance services. For example, the Metropolitan Transit System of San Diego, which represented approximately 6 million gallons of CNG in 2009, recently conducted a competitive bidding procurement and awarded the contract to a competitor as of July 27, 2010. Government deficits, spending reductions and competitive bidding procurement processes could reduce our margins on fuel sales, lower our revenue and impair our financial performance.

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 ~~our recently acquired subsidiary,~~ 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 ~~our~~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. During 2010, BAF anticipates that a similar percentage of its revenue will also be derived from sales to~~ 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 indicated that they may reduce or delay conversion of additional vehicles during 2011 in order to allow for ~~build out~~a build-out of infrastructure to support fueling the vehicles. In the absence of continued sales to AT&T, BAF ~~may~~will experience materially reduced revenues and may require ~~significant capital investment~~additional cash to continue ~~as a going concern,~~its operations, which could drain our capital resources.

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.

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Our ability to supply LNG to new and existing customers is restricted by limited production of LNG and by our ability to ~~source~~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 ~~grow~~increase the market for LNG fuel including supplying LNG fuel to heavy duty truck customers. An LNG supply interruption or LNG demand that exceeds available supply will also limit our ability to expand LNG sales to new customers and could disrupt our relationship with existing customers, which would hinder our growth. Furthermore, because transportation of LNG is relatively expensive, if we are required to supply LNG to our customers from distant locations 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 ~~impact~~impacting our LNG sales margins.

Two of our LNG supply agreements have a ~~take or pay~~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~~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 ~~LLC~~ (“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.

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

Under certain circumstances, Williams Gas Processing Company (“Williams”) may terminate our LNG supply contract with them on short notice. Williams may also significantly increase the price of LNG we purchase upon 24 hours’ notice if their costs to produce LNG increases, and we may be required to reimburse them for certain other expenses. Our contract with Williams, which supplied 29% of the LNG we sold for the year ended December 31, 2008, 14% for the year ended December 31, 2009, ~~and~~ 13.2% for the year ended December 31, 2010, and 13.6% for the first ~~nine~~three months of ~~2010,~~2011, expires on June 30, 2011. Furthermore, there are a limited number of LNG suppliers in or near the areas where our LNG customers are located. It may be difficult to replace an LNG supplier, and we may be unable to obtain alternate suppliers at acceptable prices, in a timely manner, or at all. If significant supply interruptions occur, our ability to meet customer demand will be impaired, customers may cancel orders and we may be subject to supply interruption penalties. If we are subject to LNG price increases, our operating margins may be impaired and we may be forced to sell LNG at a loss under our LNG supply contracts.

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

Some regions of the United States and Canada depend heavily on natural gas supplies coming from particular fields or pipelines. Interruptions in field production or in pipeline capacity could reduce the availability of natural gas or possibly create a supply imbalance that increases 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.

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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 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, ~~however,~~ the market price of natural gas may rise and our obligations to sell fuel under fixed price contracts may be at prices lower than our fuel purchase 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 ~~September 30, 2010,~~March 31, 2011, we were economically hedged with respect to ~~all four of~~ 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 ~~assure~~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 ~~September 30, 2010,~~March 31, 2011, we had ~~$5.9~~$4.8 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

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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 ~~September 30, 2010,~~March 31, 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 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, ~~2009~~2010 and for the ~~nine~~three months ended ~~September 30, 2010.~~March 31, 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.

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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 ~~LNG~~CNG and ~~CNG~~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 ~~LNG~~CNG and ~~CNG~~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, ~~2007,~~ 2008, 2009 and ~~2009,~~2010, sales in California accounted for ~~40%~~44%, ~~45%~~49% and 49% respectively, and sales in Arizona accounted for ~~20%~~14%, ~~14%~~10% and ~~10%~~9%, respectively, of the total amount of gallons we delivered. For the ~~nine~~three month period ended ~~September 30, 2010,~~March 31, 2011, sales in California and Arizona accounted for ~~49%~~56% and 9%15%, 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

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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. ~~The continued~~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 ~~September 30, 2010,~~March 31, 2011, we had ~~$5.9~~$3.7 million outstanding in loans provided to customers to finance natural gas vehicle purchases.

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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, which accounted for approximately 64% of our yearly revenues from 2006 through 2009.~~entities.

In connection with our LNG liquefaction activities and the landfill gas processing facility operated by ~~DCE,~~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 have 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, our business and financial results may be materially and adversely affected. 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 ~~DCE’s~~DCEMB’s landfill gas processing facility may adversely affect both ~~DCE’s~~DCEMB’s ability to supply biomethane and our operating results.

In August 2008, we acquired our 70% interest in ~~DCE. In April 2009,~~ DCE, ~~entered into~~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 ~~DCE’s~~DCEMB’s landfill gas processing facility. There is, however, no guarantee that ~~DCE~~DCEMB will be able to produce or sell up to the maximum volumes called for under the ~~agreement. DCE’s~~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 ~~DCE’s~~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 ~~DCE~~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. ~~More recently,~~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. ~~We anticipate that~~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 ~~facility will incur additional downtime for one to two weeks or more during the fall of 2010 related to replacing the plant’s gas driven compression with electric driven compression.~~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 ~~2010 and~~ 2011, and accordingly, ~~DCE’s~~DCEMB’s revenues may fluctuate from quarter to quarter.

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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 ~~(gains)~~(income) were approximately ~~$0.9 million, $3.6 million, $1.5 million, $2.9 million,~~ $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, and ~~$1.8~~$9.8 million for the three months ended ~~March 31, 2007, June 30, 2007, September 30, 2007, December 31, 2007,~~ 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, ~~and~~ September 30, 2010, December 31, 2010, and March 31, 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 ~~the recent~~any shutdowns ~~in March and June 2009 and September 2010~~ of ~~DCE’s~~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, 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 ~~outstanding Series I warrants or~~ 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.

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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 March 31, 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, ~~which is~~ $12.68 per ~~share.~~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 ~~September 30, 2010, 64,931,101~~March 31, 2011, 70,269,071 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 ~~3,314,394~~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, ~~and~~ 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 ~~the~~ IMW, ~~Acquired Business,~~ we issued 4,017,408 shares of our common stock which are also registered for immediate resale. ~~Of such~~We issued an additional 601,926 shares to the IMW shareholder in January 2011. IMW’s shareholder ~~has~~had sold ~~972,400~~3,256,166 shares of our ~~Common Stock~~common stock as of ~~September 30, 2010.~~March 31, 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 ~~September 30, 2010,~~March 31, 2011, there were ~~9,563,055~~10,705,519 shares underlying outstanding options and ~~18,314,394~~17,130,682 shares underlying outstanding warrants (including the ~~3,314,394~~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.~~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.

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Further, as of ~~September 30, 2010,~~March 31, 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 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 ~~September 30, 2010, 1,803,765~~March 31, 2011, 820,404 shares in the aggregate were subject to future ~~sale~~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 ~~September 30, 2010,~~March 31, 2011, T. Boone Pickens and affiliates (including Madeleine Pickens, his wife) owned in the aggregate ~~30%~~28% of our outstanding shares of common stock and beneficially owned in the aggregate approximately ~~43%~~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.

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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.

Item 6.—Exhibits

(a) Exhibits

~~2.5~~3.2		~~Asset Purchase Agreement, dated July 1, 2010, among Clean Energy, a California corporation, 0884808 B.C. Ltd., a British Columbia corporation,~~Amended and 0884810 B.C. Ltd., a British Columbia corporation, on the one hand, and I.M.W. Industries Ltd., a British Columbia corporation, 652322 B.C. Ltd., a British Columbia corporation, Miller Family Trust and Bradley N. Miller, on the other hand.Restated Bylaws. (Filed as Exhibit ~~2.5~~3.2 to Form 8-K, as filed with the Securities and Exchange Commission on ~~July 1, 2010,~~February 23, 2011, and incorporated herein by reference.)

~~2.6~~10.50*		~~Amendment to Asset Purchase~~Loan Agreement dated ~~as of September 7, 2010, by~~January 1, 2011, between Mission Economic Development Corporation and ~~among~~Dallas Clean Energy a California corporation, 0884808 B.C. Ltd., a British Columbia corporation and a wholly-owned subsidiary of Clean Energy — CA, and Clean Energy Compression Corp, a British Columbia corporation formerly known as 0884810 B.C. Ltd and a wholly-owned subsidiary of Canadian AcqCo, on the one hand, and I.M.W. Industries Ltd., a British Columbia Corporation, B&M Miller Equity Holdings Inc., a successor by amalgamation to 652322 B.C. Ltd., a British Columbia corporation, Bradley N. Miller, Marion G. Miller and Miller Family Trust, on the other hand. (Filed as Exhibit 2.6 to Form 8-K, as filed with the Securities and Exchange Commission on September 7, 2010, and incorporated herein by reference.)McCommas Bluff, LLC.

~~10.57~~10.51*		~~Form of Year~~Depository and Control Agreement dated January 1, ~~Note, issued by~~2011, among Dallas Clean Energy Compression Corp. to I.M.W. Industries Ltd. *

~~10.58~~		~~Form~~McCommas Bluff, LLC, The Bank of Future Payment Note, issued by Clean Energy Compression Corp. to I.M.W. Industries Ltd. *New York Mellon Trust Company, N.A. and The Bank of New York Mellon Trust Company, N.A.

~~10.59~~10.52*		~~Form~~Trust Indenture dated January 1, 2011, between Mission Economic Development Corporation and The Bank of Security Agreement between Clean Energy Compression Corp. and I.M.W. Industries Ltd. *New York Mellon Trust Company, N.A.

~~10.60~~10.53*		~~Form of Commitment to Provide Funds, between~~Bond Purchase Contract dated March 24, 2011, among Mission Economic Development Corporation, First Southwest Company, Westhoff, Cone & Holmstedt, and Dallas Clean Energy ~~Compression Corp., 0884808 B.C. Ltd., and~~McCommas Bluff, LLC.

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10.54*		Amendment to HSBC Bank Canada.*Canada Facility Letter dated March 29, 2011.

~~10.61~~10.55*		~~Form of Commitment to Provide Funds,~~Security Agreement dated March 31, 2011, between Dallas Clean Energy ~~Compression Corp., 0884808 B.C. Ltd.,~~McCommas Bluff, LLC, and ~~HSBC~~The Bank Canada.*of New York Mellon Trust Company, N.A.

~~10.62~~10.56*		~~Form~~Leasehold Deed of ~~Assumption~~Trust, Security Agreement ~~between I.M.W. Industries Ltd., IMW CNG Bangladesh Ltd., IMW Compressor Group (Shanghai) Co. Ltd., IMW Colombia Ltda., Bradley Norman Miller, Marion Miller, B&M Miller Equity Holdings Inc.,~~and Assignment of Rents and Leases dated March 31, 2011 by Dallas Clean Energy Compression Corp., Clean Energy, 0884808 B.C. Ltd., and HSBC Bank Canada.*McCommas Bluff, LLC to Peter S. Graf.

~~10.63~~		Form of General Security Agreement, between 0884808 B.C. Ltd. and HSBC Bank Canada.*

~~10.64~~		Form of Guarantee, executed by 0884808 B.C. Ltd.*

~~10.65~~		Fifth Amendment to Credit Agreement among the registrant, Clean Energy and PlainsCapital Bank.*

~~10.66~~		Seventh Amendment to Lease Agreement, dated September 23, 2010, between Clean Energy and BixbyBIT - Bixby Office Park, LLC.*

~~10.67~~		Limited Waiver and Consent, dated October 29, 2010, among the registrant, Clean Energy and PlainsCapital Bank.*

~~31.1~~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~~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~~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.*

*Filed herewith.

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SIGNATURE

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

	CLEAN ENERGY FUELS CORP.


Date: ~~November 8, 2010~~May 9, 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)

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	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
(in thousands, except per share data)	2009			2010			2009			2010

Revenue	$	40,705		$	58,372		$	113,988		$	166,192
Net loss	(20,818		)	(3,515		)	(38,176		)	(23,115		)
Loss per share
Basic	(0.33		)	(0.05		)	(0.66		)	(0.38		)
Diluted	(0.33		)	(0.05		)	(0.66		)	(0.38		)

	Gallons	Weighted Average Price Per Gasoline Gallon Equivalent
October to December, 2010	2,880,000	$	0.77
2011	11,600,000	0.82
2012	5,160,000	0.81
January to May, 2013	300,000	0.81

	Number of Shares		Weighted-Average Exercise Price
Outstanding at December 31, 2009	10,348,188		$	9.57
Granted	446,750		16.70
Exercised	(1,073,542	)	10.05
Cancelled/Forfeited	(158,341	)	13.37
Outstanding at September 30, 2010	9,563,055		9.79
Exercisable at September 30, 2010	5,879,328		8.97

	Balance at September 30, 2009			Quoted Prices In Active Markets for Identical Items (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Natural gas futures contracts obligation	$	(836,342	)	$	—	$	(836,342	)	$	—
Series I warrants	$	(30,182,411	)	$	—	$	—		$	(30,182,411	)

	Series I Warrants
Beginning Balance, January 1, 2009	$	(12,373,738	)
Total charges included in earnings for the period	(17,808,673		)
Purchases	—
Sales	—
Transfers In/Out	—
Ending Balance, September 30, 2009	$	(30,182,411	)

	Balance at September 30, 2010			Quoted Prices In Active Markets for Identical Items (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Natural gas futures contracts obligation	$	(4,970,244	)	$	—	$	(4,970,224	)	$	—
Series I warrants	$	(23,863,637	)	$	—	$	—		$	(23,863,637	)
Contingent consideration	$	(12,400,000	)	$	—	$	—		$	(12,400,000	)

	Contingent Consideration			Series I Warrants
Beginning Balance, January 1, 2010	$	(3,100,000	)	$	(29,740,491	)
Total gain included in earnings for the period	—			5,876,854
IMW Purchased obligations	(9,300,000		)	—
Sales	—			—
Transfers In/Out	—			—
Ending Balance, September 30, 2010	$	(12,400,000	)	$	(23,863,637	)

	Payments Due by Period
Contractual Obligations:	Total		Remainder of 2010		2011 and 2012		2013 through 2015		2016 and beyond
Debt and capital lease obligations(a)	$	69,362,439	$	7,365,134	$	32,760,521	$	29,236,784	$	0
Operating lease commitments(b)	23,658,220		857,510		6,148,529		9,135,393		7,516,788
“Take or pay” LNG purchase contracts(c)	23,160,094		1,263,356		7,114,350		9,175,275		5,607,113
Construction contracts(d)	17,246,326		12,888,778		4,357,548		0		0
Total	$	133,427,079	$	22,374,778	$	50,380,948	$	47,547,452	$	13,123,901