Edgar Filing: Clean Energy Fuels Corp.

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

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

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2012

Commission File Number: 001-33480

CLEAN ENERGY FUELS CORP.

(Exact name of registrant as specified in its charter)

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

3020 Old Ranch Parkway, Suite 400, Seal Beach CA 90740

(Address of principal executive offices, including zip code)

(562) 493-2804

(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer o		Accelerated filer x

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

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

As of July 30, 2012, there were 86,929,434 shares of the registrant’s common stock, par value $0.0001 per share, issued and outstanding.

Table of Contents

CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

INDEX

Table of Contents

PART I.—FINANCIAL INFORMATION
Item 1.—Financial Statements (Unaudited)	3
Item 2.—Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.—Quantitative and Qualitative Disclosures About Market Risk	34
Item 4.—Controls and Procedures	35
PART II.—OTHER INFORMATION
Item 1.—Legal Proceedings	35
Item 1A.—Risk Factors	35
Item 2.—Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 3.—Defaults upon Senior Securities	47
Item 4.— Mine Safety Disclosures	47
Item 5.—Other Information	47
Item 6.—Exhibits	47

Table of Contents

PART I.—FINANCIAL INFORMATION

Item 1.—Financial Statements (Unaudited)

Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Balance Sheets

As of December 31, 2011 and June 30, 2012

(Unaudited)

(In thousands, except share data)

	December 31, 2011			June 30, 2012
Assets
Current assets:
Cash and cash equivalents	$	238,125		$	172,715
Restricted cash	4,792			7,067
Short-term investments	33,329			37,079
Accounts receivable, net of allowance for doubtful accounts of $712 and $859 as of December 31, 2011 and June 30, 2012, respectively	56,455			63,565
Other receivables	19,601			20,976
Inventory, net	35,287			36,470
Prepaid expenses and other current assets	14,027			15,132
Total current assets	401,616			353,004
Land, property and equipment, net	277,334			355,017
Restricted cash	54,804			21,348
Notes receivable and other long-term assets	16,650			16,853
Investments in other entities	16,459			16,954
Goodwill	73,741			73,741
Intangible assets, net	102,103			100,749
Total assets	$	942,707		$	937,666
Liabilities and Stockholders’ Equity
Current liabilities:
Current portion of long-term debt and capital lease obligations	$	22,925		$	33,784
Accounts payable	36,668			31,733
Accrued liabilities	28,255			29,151
Deferred revenue	21,267			44,389
Total current liabilities	109,115			139,057
Long-term debt and capital lease obligations, less current portion	266,497			253,830
Other long-term liabilities	22,687			22,620
Total liabilities	398,299			415,507
Commitments and contingencies (Note 16)
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 85,433,258 shares and 86,790,309 shares at December 31, 2011 and June 30, 2012, respectively	9			9
Additional paid-in capital	741,650			760,938
Accumulated deficit	(199,559		)	(242,758		)
Accumulated other comprehensive loss	(1,216		)	225
Total Clean Energy Fuels Corp. stockholders’ equity	540,884			518,414
Noncontrolling interest in subsidiary	3,524			3,745
Total stockholders’ equity	544,408			522,159
Total liabilities and stockholders’ equity	$	942,707		$	937,666

See accompanying notes to condensed consolidated financial statements.

Table of Contents

Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Statements of Operations

For the Three Months and Six Months Ended June 30, 2011 and 2012

(Unaudited)

(In thousands, except share and per share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2012			2011			2012
Revenue:
Product revenues	$	61,523		$	57,705		$	120,055		$	123,481
Service revenues	7,590			12,137			14,399			19,995
Total revenues	69,113			69,842			134,454			143,476
Operating expenses:
Cost of sales:
Product cost of sales	46,888			43,691			90,737			95,593
Service cost of sales	3,536			4,839			6,690			8,823
Derivative (gains) losses:
Series I warrant valuation	(4,835		)	(8,899		)	(1,535		)	4,607
Selling, general and administrative	21,653			27,916			39,683			52,766
Depreciation and amortization	7,632			8,907			14,842			17,051
Total operating expenses	74,874			76,454			150,417			178,840
Operating loss	(5,761		)	(6,612		)	(15,963		)	(35,364		)
Interest expense, net	(1,506		)	(3,321		)	(2,327		)	(7,023		)
Other income (expense), net	187			(1,177		)	788			(336		)
Income from equity method investments	164			72			375			163
Loss before income taxes	(6,916		)	(11,038		)	(17,127		)	(42,560		)
Income tax benefit (expense)	1,177			(172		)	1,912			(418		)
Net loss	(5,739		)	(11,210		)	(15,215		)	(42,978		)
Loss (income) of noncontrolling interest	120			(84		)	(157		)	(221		)
Net loss attributable to Clean Energy Fuels Corp.	$	(5,619	)	$	(11,294	)	$	(15,372	)	$	(43,199	)
Loss per share attributable to Clean Energy Fuels Corp.
Basic	$	(0.08	)	$	(0.13	)	$	(0.22	)	$	(0.50	)
Diluted	$	(0.08	)	$	(0.13	)	$	(0.22	)	$	(0.50	)
Weighted average common shares outstanding
Basic	70,302,782			86,625,655			70,199,963			86,155,678
Diluted	70,302,782			86,625,655			70,199,963			86,155,678

See accompanying notes to condensed consolidated financial statements.

Table of Contents

Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income

For the Three Months and Six Months Ended June 30, 2011 and 2012

(Unaudited)

(In thousands)

	Clean Energy Fuels Corp.						Noncontrolling Interest					Total
	Three Months Ended June 30,						Three Months Ended June 30,					Three Months Ended June 30,
	2011			2012			2011			2012		2011			2012
Net income (loss)	$	(5,619	)	$	(11,294	)	$	(120	)	$	84	$	(5,739	)	$	(11,210	)

Other comprehensive income, net of tax:
Foreign currency translation adjustments	6			24			—			—		6			24
Unrealized losses on available-for-sale securities	—			(100		)	—			—		—			(100		)
Unrecognized gains on derivatives	505			1,251			—			—		505			1,251
Total other comprehensive income, net of tax	511			1,175			—			—		511			1,175

Comprehensive income (loss)	$	(5,108	)	$	(10,119	)	$	(120	)	$	84	$	(5,228	)	$	(10,035	)

	Clean Energy Fuels Corp.						Noncontrolling Interest				Total
	Six Months Ended June 30,						Six Months Ended June 30,				Six Months Ended June 30,
	2011			2012			2011		2012		2011			2012
Net income (loss)	$	(15,372	)	$	(43,199	)	$	157	$	221	$	(15,215	)	$	(42,978	)

Other comprehensive income, net of tax:
Foreign currency translation adjustments	(697		)	(309		)	—		—		(697		)	(309		)
Unrealized losses on available-for-sale securities	—			(216		)	—		—		—			(216		)
Unrecognized gains on derivatives	1,213			1,966			—		—		1,213			1,966
Total other comprehensive income, net of tax	516			1,441			—		—		516			1,441

Comprehensive income (loss)	$	(14,856	)	$	(41,758	)	$	157	$	221	$	(14,699	)	$	(41,537	)

See accompanying notes to condensed consolidated financial statements.

Table of Contents

Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

For the Six Months Ended June 30, 2011 and 2012

(Unaudited)

(In thousands)

	Six Months Ended June 30,
	2011			2012
Cash flows from operating activities:
Net loss	$	(15,215	)	$	(42,978	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization	14,842			17,051
Provision for doubtful accounts and notes	255			374
Derivative (gain) loss	(1,535		)	4,607
Stock-based compensation expense	6,932			10,448
Amortization of debt issuance cost	114			230
Accretion of notes payable	1,388			1,037
Gain on contingent consideration for acquisitions	(700		)	(4,294		)
Changes in operating assets and liabilities, net of assets and liabilities acquired:
Accounts and other receivables	18,595			(8,809		)
Inventory	(9,004		)	(231		)
Margin deposits on futures contracts	2,981			1,276
Prepaid expenses and other assets	(2,940		)	(2,830		)
Accounts payable	(2,066		)	(4,935		)
Accrued expenses and other	(3,761		)	22,803
Net cash provided by (used in) operating activities	9,886			(6,251		)
Cash flows from investing activities:
Purchases of short-term investments	—			(21,210		)
Maturities of short-term investments	—			17,244
Purchases of property and equipment	(27,585		)	(89,258		)
Change in restricted cash	(27,413		)	31,181
Investments in other entities	(2,700		)	(1,024		)
Net cash used in investing activities	(57,698		)	(63,067		)
Cash flows from financing activities:
Proceeds from issuance of common stock and exercise of stock options	733			7,836
Proceeds from capital lease obligations and debt instruments	41,850			384
Contingent consideration paid relating to business acquisitions	(2,159		)	(350		)
Proceeds from revolving line of credit	21,945			24,418
Proceeds from minority interest DCE equity contribution	417			—
Payments for debt issuance costs	(1,767		)	—
Repayment of borrowing under revolving line of credit	(16,665		)	(23,136		)
Repayment of capital lease obligations and debt instruments	(15,497		)	(6,111		)
Net cash provided by financing activities	28,857			3,041
Effect of exchange rates on cash and cash equivalents	(963		)	867
Net decrease in cash	(19,918		)	(65,410		)
Cash, beginning of period	55,194			238,125
Cash, end of period	$	35,276		$	172,715
Supplemental disclosure of cash flow information:
Income taxes paid	$	266		$	680
Interest paid, net of approximately $125 and $3,184 capitalized, respectively	714			6,030

See accompanying notes to condensed consolidated financial statements.

Table of Contents

Clean Energy Fuels Corp. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(In thousands, except share data)

Note 1—General

Nature of Business: Clean Energy Fuels Corp., together with its majority and wholly owned subsidiaries (hereinafter collectively referred to as the “Company”) is engaged in the business of selling natural gas fueling solutions to its customers, primarily in the United States. The Company began selling certain equipment and services internationally in 2010 as a result of its acquisition of I.M.W. Industries, Ltd. (“IMW”).

The Company has a broad customer base in a variety of markets, including trucking, airports, taxis, refuse, and public transit. The Company, builds, operates, maintains or supplies approximately 313 natural gas fueling locations in twenty-nine states within the United States, and in British Columbia and Ontario within Canada. The Company also generates revenue through operation and maintenance (“O&M”) agreements with certain customers, through building and selling or leasing natural gas fueling stations to its customers, and through manufacturing and servicing natural gas fueling compressors and related equipment, providing natural gas vehicle conversions, processing and selling renewable natural gas (“RNG”), and through financing its customers’ vehicle purchases.

Basis of Presentation: The accompanying interim unaudited condensed consolidated financial statements include the accounts of the Company and its subsidiaries, and, in the opinion of management, reflect all adjustments, which include only normal recurring adjustments, necessary to state fairly the Company’s financial position, results of operations and cash flows for the three and six month periods ended June 30, 2011 and 2012. All intercompany accounts and transactions have been eliminated in consolidation. The three and six month periods ended June 30, 2011 and 2012 are not necessarily indicative of the results to be expected for the year ending December 31, 2012 or for any other interim period or for any future year.

Certain information and disclosures normally included in the notes to the financial statements have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”), but the resultant disclosures contained herein are in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) as they apply to interim reporting. The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements as of and for the year ended December 31, 2011 that are included in the Company’s Annual Report on Form 10-K filed with the SEC on March 12, 2012.

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 recorded 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

ServoTech

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, among other services, design and engineering services for natural gas fueling systems. In connection with the investment, the Company was granted an option to purchase the remaining 80.1% of ServoTech for $2,800 during the 15 month period following the Closing Date (the “Purchase Option”). On April 30, 2012, the Company exercised the Purchase Option, paid $1,400 in cash on that date, and agreed to pay an additional $1,400 in cash on October 31, 2012. Through March 31, 2012, the Company accounted for its interest in ServoTech using the equity method of accounting as the Company had the ability to exercise significant influence over ServoTech’s operations.

Table of Contents

The Company accounted for this acquisition in accordance with the authoritative guidance for business combinations in stages. The Company re-measured its previously held equity interest in ServoTech at fair value as of April 30, 2012 (its acquisition date) resulting in no gain or loss, and recognized the assets acquired and the liabilities assumed, measured at their fair values, as of the date of acquisition. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed as of the acquisition date:

Current assets	$	2,655
Property & equipment	239
Identifiable intangible assets	3,913
Total assets acquired	6,807
Current liabilities assumed	(2,807		)
Total purchase price	$	4,000

The Company identified intangible assets with estimated fair value of $3,913 related to certain customer contracts and technology. The fair value of the identified intangible assets will be amortized on a straight-line basis over their estimated useful lives, ranging from two to seven years.

The results of ServoTech’s operations have been included in the Company’s consolidated financial statements since April 30, 2012. The historical results of ServoTech’s operations were not material to the Company’s financial position or historical results of operations.

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— Restricted Cash

The Company classifies restricted cash as a current asset if the cash is expected to be used in operations within a year or to acquire a current asset. Otherwise, the restricted cash is classified as long-term. Restricted cash consisted of the following as of June 30, 2012:

	December 31, 2011		June 30, 2012
Short-term restricted cash
Standby letters of credit	$	1,237	$	1,217
DCEMB bonds — current operating costs	3,555		5,850
Total short-term restricted cash	4,792		7,067
Chesapeake loan	40,322		16,722
DCEMB bonds — long-term plant expansion	14,482		4,626
Total restricted cash	$	59,596	$	28,415

Note 5— Investments

Available-for-sale investments are carried at fair value, inclusive of unrealized gains and losses. Net unrealized gains and losses are included in other comprehensive income (loss) net of applicable income taxes. Gains or losses on sales of available-for-sale investments are recognized on the specific identification basis.

The Company reviews available-for-sale investments for other-than-temporary declines in fair value below their cost basis each quarter, and whenever events or changes in circumstances indicate that the cost basis of an asset may not be recoverable. This evaluation is based on a number of factors, including the length of time and the extent to which the fair value has been below its cost basis and adverse conditions related specifically to the security, including any changes to the credit rating of the security. As of June 30, 2012 the Company believes its cost bases for its available-for-sale investments are properly recorded.

Available-for-sale securities as of December 31, 2011 are summarized as follows:

	Amortized Cost		Gross Unrealized Losses			Estimated Fair Value
Municipal bonds & notes	$	19,703	$	(114	)	$	19,589
Zero coupon bonds	712		—			712
Corporate bonds	3,040		(12		)	3,028
Total available-for-sale securities	23,455		(126		)	23,329
Certificate of deposits	10,000		—			10,000
Total short-term investments	$	33,455	$	(126	)	$	33,329

Table of Contents

Available-for-sale securities as of June 30, 2012 are summarized as follows:

	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
Municipal bonds & notes	$	23,032	$	—	$	(305	)	$	22,727
Zero coupon bonds	810		3		—			813
Corporate bonds	3,558		—		(40		)	3,518
Total available-for-sale securities	27,400		3		(345		)	27,058
Certificate of deposits	10,021		—		—			10,021
Total short-term investments	$	37,421	$	3	$	(345	)	$	37,079

The Company had no available-for-sale securities as of June 30, 2011.

Note 6—Derivative Transactions

As of June 30, 2012, all of the Company’s future contracts qualified for hedge accounting. 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 Financial Accounting Standards Board’s (“FASB”) authoritative guidance. For the three month periods ended June 30, 2011 and 2012, the Company recorded unrealized gains of $505 and $1,251, respectively, in other comprehensive income (loss) related to its futures contracts. The Company recorded unrealized gains of $1,213 and $1,966 in other comprehensive income (loss) for the six month periods ended June 30, 2011 and 2012, respectively, related to its futures contracts. The liability of the Company’s future contracts at June 30, 2012 was $293, which is included in accrued liabilities in the Company’s consolidated balance sheet. Of the $2,858 liability for the Company’s futures contracts at June 30, 2011, $2,715 is included in accrued liabilities for the short-term amount, and $143 is included in other long-term liabilities for the long-term amount in the Company’s condensed consolidated balance sheet. The Company’s ineffectiveness related to its futures contracts during the three and six month periods ended June 30, 2011 and 2012 was insignificant. For the three months ended June 30, 2011 and 2012, the Company recognized a loss of approximately $680 and $1,196, respectively, in cost of sales in the accompanying condensed consolidated statements of operations related to its futures contracts that were settled during the respective periods. For the six months ended June 30, 2011 and 2012, the Company recognized a loss of $1,431 and $2,303, respectively, in cost of sales in the accompanying condensed consolidated statements of operations related to its futures contracts that were settled during the respective periods.

The following table presents the notional amounts and weighted-average fixed prices per gasoline gallon equivalent of the Company’s natural gas futures contracts as of June 30, 2012:

	Gallons	Weighted Average Price Per Gasoline Gallon Equivalent
July to December, 2012	440,000	$	0.79
January to May, 2013	300,000	$	0.81

Note 7—Other Receivables

Other receivables at December 31, 2011 and June 30, 2012 consisted of the following:

	December 31, 2011		June 30, 2012
Loans to customers to finance vehicle purchases	$	1,789	$	2,223
Capital lease receivables	310		301
Accrued customer billings	5,860		8,701
Fuel tax and carbon credits	5,912		4,038
Other	5,730		5,713
	$	19,601	$	20,976

Table of Contents

Note 8—Inventories

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

Inventories consisted of the following as of December 31, 2011 and June 30, 2012:

	December 31, 2011		June 30, 2012
Raw materials and spare parts	$	30,177	$	30,790
Work in process	2,310		4,170
Finished goods	2,800		1,510
Total	$	35,287	$	36,470

Note 9—Land, Property and Equipment

Land, property and equipment at December 31, 2011 and June 30, 2012 are summarized as follows:

	December 31, 2011			June 30, 2012
Land	$	1,198		$	1,198
LNG liquefaction plants	93,109			93,317
RNG plants	21,005			22,356
Station equipment	118,613			135,866
LNG trailers	13,532			13,564
Other equipment	26,508			37,383
Construction in progress	86,127			146,211
	360,092			449,895
Less: accumulated depreciation	(82,758		)	(94,878		)
	$	277,334		$	355,017

Note 10—Investments in Other Entities

The Company has invested in The Vehicle Production Group LLC (“VPG”), a company that is developing a natural gas vehicle made in the United States for taxi and paratransit use. The Company accounts for its investment in VPG under the cost method of accounting as the Company does not have the ability to exercise significant influence over VPG’s operations. During the six months ended June 30, 2012, the Company invested an additional $1,024 in VPG. At June 30, 2012, this investment had a balance of $14,544.

The Company has invested in Clean Energy del Peru (“Peru JV”), a joint venture in Lima, Peru that operates CNG stations. The Company accounts for its investment in Peru JV under the equity method of accounting as the Company has the ability to exercise significant influence over Peru JV’s operations. At June 30, 2012, this investment had a balance of $2,410.

Note 11— Accrued Liabilities

Accrued liabilities at December 31, 2011 and June 30, 2012 consisted of the following:

	December 31, 2011		June 30, 2012
Salaries and wages	$	5,088	$	6,059
Accrued gas and equipment purchases	4,773		7,225
Derivative liabilities	2,259		610
Contingent consideration obligations	378		864
Accrued property and other taxes	3,043		1,639
Accrued professional fees	875		914
Accrued employee benefits	1,431		3,328
Accrued warranty liability	3,130		3,020
Other	7,278		5,492
	$	28,255	$	29,151

Table of Contents

Note 12—Warranty Liability

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

	June 30, 2011			June 30, 2012
Warranty liability at beginning of year	$	2,338		$	3,130
Costs accrued for new warranty contracts and changes in estimates for pre-existing warranties	723			2,028
Service obligations honored	(332		)	(2,138		)
Warranty liability at end of period	$	2,729		$	3,020

Note 13—Long-term Debt

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

On October 7, 2009, the Facility A Loan was repaid in full and converted into a $20,000 line of credit (the “A Line of Credit”) pursuant to an amendment to the Credit Agreement. On August 13, 2010, the Credit Agreement was amended to extend the maturity date of the A Line of Credit to August 14, 2011 and add an unused facility fee. The amendment also provided for a 1-year option to extend the maturity date to August 14, 2012, subject to the Company not being in default on the A Line of Credit. The unused facility fees are to be paid quarterly, in an amount equal to one-tenth of one percent (0.10%) of the unused portion. The Company elected not to renew the A Line of Credit on August 14, 2011 and the Line of Credit expired on that date. The principal amount of the Facility B Loan became due and payable in annual payments commencing on August 1, 2009, and continuing each anniversary date thereafter, with each such payment being in an amount equal to the lesser of twenty percent of the aggregate principal amount of the Facility B Loan then outstanding or $2,800. Pursuant to an amendment to the Facility B loan between the Company and PCB dated November 1, 2010, PCB agreed to forgo the scheduled payment due from the Company on August 2010 in the amount of $2,059 until January 31, 2011, which payment was made on such date. On March 31, 2011, the Company paid in full the remaining principal and interest that was due under the Facility B Loan.

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

Revenue Bonds

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 RNG. The Revenue Bonds are secured by the revenue and assets of DCEMB and are non-recourse to DCEMB’s direct and indirect parent companies, including the Company. The bond repayments are amortized through December 2024 and the average coupon interest rate on the bonds is 6.60%. The bond issuance closed March 31, 2011.

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

Table of Contents

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

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

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

All payments received by the Depository Bank will be placed into various accounts in accordance with the requirements of the Indenture and the Depository Agreement. The funds in these accounts will be used to service required debt payments, finance further improvements and expansion of the landfill gas processing facility owned by DCEMB, finance the operations and maintenance of DCEMB, finance certain expenses associated with setting up and maintaining the accounts, and other uses as prescribed in the Depository Agreement. The Depository Bank will make payments out of these accounts in accordance with the requirements of the Depository Agreement. At the end of each month after all required account fundings have been fulfilled in accordance with the Depository Agreement, all remaining excess funds will be placed into a surplus account. The funds in the surplus account will be delivered to DCEMB so long as (i) DCEMB’s Debt Service Coverage Ratio (as defined) for the most recent four calendar quarters then ended equals or exceeds 1.25:1, (ii) DCEMB’s Debt Service Coverage Ratio (as defined) is reasonably projected to equal or exceed 1.25:1 for the next four calendar quarters, (iii) no events of default have occurred as defined by the Indenture and the Loan Agreement, and (iv) after giving effect to the transfer, DCEMB’s Minimum Days Cash on Hand (as defined) shall be, or shall at any time be projected to be, more than the lesser of thirty-five Days Cash on Hand (as defined) or $1,300. Due to these restrictions on this cash, the Company has classified all of this cash as restricted cash on the balance sheet. The Company records the restricted cash that is expected to be received and used within the next 12 months from the Depository Bank for working capital and operating purposes as current in its balance sheet, and presents the remaining balance as non-current in the line item notes receivable and other long term assets. At June 30, 2012, $4,626 was recorded as long term restricted cash and $5,850 was recorded as short term restricted cash in the accompanying condensed consolidated balance sheet.

Pursuant to a Collateral Assignment and Consent 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.

The Indenture and the Loan Agreement have certain non-financial debt covenants with which DCEMB must comply. As of June 30, 2012, DCEMB was in compliance with all its debt covenants.

Purchase Notes

In connection with the closing of the Company’s acquisition of IMW in September 2010, the Company agreed to make future payments consisting of four annual payments in the amount of $12,500 (collectively the “IMW Notes”). Each payment under the IMW Notes will consist of $5,000 in cash and $7,500 in cash and/or shares of the Company’s common stock (the exact combination of cash and/or stock to be determined at the Company’s option). In addition, pursuant to a security agreement executed at closing, the IMW Notes are secured by a subordinate security interest in IMW.

In connection with the closing of the Company’s acquisition of Northstar in December 2010, the Company agreed to make five annual payments in the amount of $700 each with the first payment due December 15, 2011. The first payment of $700 was paid on December 15, 2011.

Table of Contents

In connection with the closing of the Company’s acquisition of Weaver Electric, Inc. on October 3, 2011, the Company paid $1,000 in cash and agreed to make four additional annual payments in the amount of $250 each with the first payment due October 3, 2012. In May 2012, the Company prepaid $125 of the amount due on October 3, 2012.

The difference between the carrying amount and the face amount of these obligations is being accreted to interest expense over the remaining term of the obligations.

IMW Lines of Credit

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

(i) An operating line of credit with a limit of $10,000 in Canadian dollars (“CAD”) to assist in financing the day-to-day working capital needs of IMW. The interest on amounts outstanding shall be payable at IMW’s option at (a) HSBC’s Prime Rate plus 1.00% per annum, (b) HSBC’s U.S. Base Rate plus 1.00% per annum, or LIBOR plus 2.25% per annum, subject to availability.

(ii) A demand revolving line of credit with a limit of CAD$2,000 bearing interest at the same rate as that of the operating line of credit discussed above, to assist in financing IMW’s import requirements.

(iii) A demand revolving bank guarantee and standby letter of credit line with a limit of CAD$1,115.

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

(v) A forward exchange contract line with a limit of CAD$13,750 that allows IMW to enter into foreign exchange forward contracts up to the notional limit of CAD$13,750 (no forward exchange contracts were outstanding at June 30, 2012).

(vi) A MasterCard with a limit of CAD$150.

(vii) An operating line of credit with a limit of 5,000 Renminbi (“RMB”) (CAD$811) bearing interest at the 6 month People’s Bank of China rate plus 2.5% and a sub-limit bank guarantee line of 5,000 RMB. The aggregate of the balances in the lines cannot exceed 5,000 RMB.

(viii) A 16,750 Bengali Taka (CAD$206) operating line of credit bearing interest at 14%.

(ix) A 170,000 Columbian Peso (CAD$97) operating line of credit bearing interest at the Colombia benchmark rate plus 7 to 12%.

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

The Assumption Agreement with HSBC sets forth certain financial covenants with which IMW must comply, including: 1) its ratio of debt to tangible net worth must be no greater than 3.75 to 1.0 from January 1, 2012 through March 31, 2012, and no greater than 3.5 to 1.0 from April 1, 2012 through June 30, 2012, and no greater than 3.0 to 1.0 on or after July 1, 2012, 2) it must maintain a tangible net worth of at least CAD$7,000 and 3) its ratio of current assets to current liabilities may not be less than 1.15 to 1.0 until March 31, 2012 or less than 1.25 to 1.0 on or after April 1, 2012. IMW was in compliance with the financial covenants as of June 30, 2012.

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

Table of Contents

Chesapeake Notes

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

The first CHK Note was issued on July 11, 2011, the second CHK Note was issued on July 10, 2012, and the Company expects to issue the third Note on or about June 28, 2013. The CHK Notes bear interest at the rate of 7.5% per annum (payable quarterly, in arrears, on March 31, June 30, September 30 and December 31 of each year) and are convertible at Chesapeake’s option into shares of the Company’s common stock at a conversion price of $15.80 per share (the “CHK Conversion Price”). Subject to certain restrictions, the Company can force conversion of each CHK Note into shares of the Company’s common stock if, following the second anniversary of the issuance of a CHK Note, the Company’s shares of common stock trade at a 40% premium to the CHK Conversion Price for at least 20 trading days in any consecutive 30 trading day period. The entire principal balance of each CHK Note is due and payable seven years following its issuance, and the Company may repay each CHK Note in shares of the Company’s common stock or cash. The CHK Agreement restricts the use of the CHK Financing proceeds to financing the development, construction and operation of liquefied natural gas stations and payment of certain related expenses. At June 30, 2012, approximately $16,722 of these funds were included in long term restricted cash as the Company anticipates primarily using the funds to build liquefied natural gas fueling stations. The CHK Agreement also provides for customary events of default which, if any of them occurs, would permit or require the principal of, and accrued interest on, the CHK Notes to become, or to be declared, due and payable.

In connection with the CHK Financing, the Company also entered into a Registration Rights Agreement, dated July 11, 2011, with Chesapeake (the “CHK Registration Rights Agreement”) pursuant to which the Company agreed, subject to the terms and conditions of the CHK Registration Rights Agreement, to (i) file with the Securities and Exchange Commission one or more registration statements relating to the resale of the Company’s common stock issuable upon conversion of the CHK Notes, and (ii) at the request of Chesapeake, to participate in one or more underwritten offerings of the Company’s common stock issuable upon conversion of the CHK Notes. If the Company does not meet certain of its obligations under the CHK Registration Rights Agreement with respect to the registration of the Company’s common stock, it will be required to pay monthly liquidated damages of 0.75% of the principal amount of the CHK Note represented by the Company’s common stock included (or to be included, as the case may be) in the applicable registration statement until the related obligation is met. As of June 30, 2012, the Company met its obligations under the CHK Registration Rights Agreement.

SLG Notes

On August 24, 2011, the Company entered into Convertible Note Purchase Agreements (each, an “SLG Agreement” and collectively the “SLG Agreements”) with each of Springleaf Investments Pte. Ltd., a wholly-owned subsidiary of Temasek Holdings Pte. Ltd., Lionfish Investments Pte. Ltd., an investment vehicle managed by Seatown Holdings International Pte. Ltd., and Greenwich Asset Holding Ltd., a wholly-owned subsidiary of RRJ Capital Master Fund I, L.P. (each, a “Purchaser” and collectively, the “Purchasers”), whereby the Purchasers agreed to purchase from the Company $150 million of 7.5% convertible notes due in August 2016 (each a “SLG Note” and collectively the “SLG Notes”). The transaction closed and the SLG Notes were issued on August 30, 2011.

The SLG Notes bear interest at the rate of 7.5% per annum (payable quarterly, in arrears, on March 31, June 30, September 30 and December 31 of each year) and are convertible at each Purchaser’s option into shares of the Company’s common stock at a conversion price of $15.00 per share (the “SLG Conversion Price”). Subject to certain restrictions, the Company can force conversion of each SLG Note into shares of the Company’s common stock if, following the second anniversary of the issuance of the SLG Notes, the Company’s shares of common stock trade at a 40% premium to the SLG Conversion Price for at least 20 trading days in any consecutive 30 trading day period. The entire principal balance of each SLG Note is due and payable five years following its issuance, and the Company may repay the principal balance of each SLG Note in shares of the Company’s common stock or cash. The SLG Agreements also provide for customary events of default which, if any of them occurs, would permit or require the principal of, and accrued interest on, the SLG Notes to become, or to be declared, due and payable. In April 2012, $1,003 of principal and accrued interest under a SLG Note was converted by the holder thereof into 66,888 shares of the Company’s common stock.

Table of Contents

In connection with the SLG Agreements, the Company also entered into a Registration Rights Agreement, dated August 24, 2011, with each of the Purchasers (the “SLG Registration Rights Agreements”) pursuant to which the Company agreed, subject to the terms and conditions of the SLG Registration Rights Agreements, to (i) file with the Securities and Exchange Commission one or more registration statements relating to the resale of the Company’s common stock issuable upon conversion of the SLG Notes, and (ii) at the request of the Purchasers, participate in one or more underwritten offerings of the Company’s common stock issuable upon conversion of the SLG Notes. If the Company does not meet certain of its obligations under the SLG Registration Rights Agreements with respect to the registration of the Company’s common stock, it will be required to pay monthly liquidated damages of 0.75% of the principal amount of the SLG Note represented by the Company’s common stock included (or to be included, as the case may be) in the applicable registration statement until the related obligation is met, not to exceed 4% of the aggregate principal amount of the SLG Notes per annum. As of June 30, 2012, the Company met its obligations under the SLG Registration Rights Agreement.

Long-term debt at December 31, 2011 and June 30, 2012 consisted of the following:

	December 31, 2011			June 30, 2012
IMW Notes	$	34,400		$	30,391
Northstar future payments	2,388			2,468
ServoTech future payment	—			1,400
DCE Notes	585			585
DCEMB Revenue Bonds (non recourse to the Company)	39,400			39,400
Chesapeake Notes	50,000			50,000
SLG Notes	150,000			149,000
Weaver Electric future payments	872			782
IMW assumed debt	6,657			9,449
Capital lease obligations	5,120			4,139
Total debt and capital lease obligations	289,422			287,614
Less amounts due within one year and short-term borrowings	(22,925		)	(33,784		)
Total long-term debt and capital lease obligations	$	266,497		$	253,830

Note 14—Earnings Per Share

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

	Three Months Ended June 30,		Six Months Ended June 30,
	2011	2012	2011	2012
Basic and diluted:
Weighted average number of common shares outstanding	70,302,782	86,625,655	70,199,963	86,155,678

Certain securities were excluded from the diluted earnings per share calculations for the six-months ended June 30, 2011 and 2012, respectively, as the inclusion of the securities would be anti-dilutive to the calculation. The amounts outstanding as of June 30, 2011 and 2012 for these instruments are as follows:

	June 30,
	2011	2012
Options	10,802,155	10,564,834
Warrants	17,130,682	2,130,682
Convertible notes	—	13,097,669
Restricted stock units	—	1,545,000

Note 15—Stock-Based Compensation

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2012		2011		2012

Stock-based compensation expense	$	3,555	$	5,768	$	6,932	$	10,448
Stock-based compensation expense, net of tax	$	3,555	$	5,768	$	6,932	$	10,448

Table of Contents

Stock Options

The following table summarizes the Company’s stock option activity during the six months ended June 30, 2012:

	Number of Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value
Outstanding, December 31, 2011	10,683,303		$	10.29
Options granted	1,274,000		15.07
Options exercised	(1,290,163	)	6.07
Options forfeited	(102,306	)	13.99
Outstanding, June 30, 2012	10,564,834		$	11.34	6.45	$	43,950
Exercisable, June 30, 2012	7,451,848		$	10.05	5.48	$	40,613

As of June 30, 2012, there was $20,636 of total unrecognized compensation cost related to non-vested shares. That cost is expected to be recognized over a weighted average period of 1.3 years. The total fair value of shares vested during the six months ended June 30, 2012 was $3,670.

The Company plans to issue new shares to its employees upon the employee’s exercise of their options. The intrinsic value of all options exercised during the six months ended June 30, 2011 and 2012 was $657 and $11,459, respectively.

The fair value of each option is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions used for grants in 2012:

		Six Months Ended June 30, 2012
Dividend yield		0.00%
Expected volatility		66.2% to 72.8%
Risk-free interest rate		00.9% to 01.2%
Expected life in years		6.0

The weighted-average grant date fair values of options granted during the six months ended June 30, 2011 and 2012 were $9.07, and $9.09, 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 volatility of its traded options. The expected lives used during the periods were based on historical exercise periods and the Company’s anticipated exercise periods for its outstanding options. The risk free rates used during the year were based on the U.S. Treasury yield curve for the expected life of the options at the time of grant. The Company recorded $6,932 and $6,970 of stock option expense during the six months ended June 30, 2011 and 2012, respectively. The Company has not recorded any tax benefit related to its stock option expense.

Restricted Stock Units

The Company issued restricted stock units (“RSUs”) to certain key employees during the six months ended June 30, 2012. A holder of RSUs will receive one share of the Company’s common stock for each RSU he holds if (x) between two years and four years from the date of grant the closing price of the Company’s common stock equals or exceeds, for twenty consecutive trading days, 135% of the closing price of the Company’s common stock on the RSU grant date (the “Stock Price Condition”) and (y) the holder is employed by the Company at the time the Stock Price Condition is satisfied. If the Stock Price Condition is not satisfied prior to four years from the date of grant, the RSUs will be automatically forfeited. The RSUs are subject to the terms and conditions of the Company’s Amended and Restated 2006 Equity Incentive Plan and a Notice of Grant of Restricted Stock Unit and Restricted Stock Unit Agreement.

The fair value of the RSUs was estimated using a binomial lattice model that incorporates a Monte Carlo Simulation (the “Monte Carlo Method”).

Table of Contents

The following table summarizes the Company’s RSU activity during the six months ended June 30, 2012:

	Number of Shares	Weighted Average Fair Value at Grant Date		Weighted Average Remaining Contractual Term (in years)
Outstanding, December 31, 2011	—	—
Granted	1,545,000	$	11.42
Outstanding and non-vested, June 30, 2012	1,545,000	$	11.42	3.7

As of June 30, 2012, there was $14,164 of total unrecognized compensation cost related to non-vested units. That cost is expected to be recognized over a weighted average period of 1.7 years.

The fair value of each RSU was estimated on the date of grant using the Monte Carlo Method with the following assumptions:

	January 25, 2012			May 8, 2012
Stock price on date of grant	$	15.11		$	16.71
Dividend yield	0.00		%	0.00		%
Expected volatility	56.51		%	58.49		%
Risk-free interest rate	0.57		%	0.56		%
Expected life in years	2.1			2.0

The volatility amounts used during the period were estimated based on the Company’s historical volatility for a period commensurate with the term of the RSUs granted and the Company’s implied volatility of its traded options. The expected life of the RSUs was derived using the Monte Carlo Method. The risk free rates used during the year were based on the U.S. Treasury yield curve for the expected term of the RSUs at the date of grant. The Company recorded $3,478 of expense and has not recorded any tax benefit related to the expense of the RSUs during the six months ended June 30, 2012.

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 which would have a material impact on the Company’s consolidated financial position, results of operations, or liquidity. The Company believes that its operations comply, in all material respects, with applicable federal, state, local and foreign environmental laws and regulations.

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

On July 15, 2010, the Internal Revenue Service (“IRS”) sent the Company a letter disallowing approximately $5,073 related to certain claims it made from October 1, 2006 to June 30, 2008 under the Volumetric Excise Tax Credit (“VETC”) program. The Company believes its claims were properly made and has appealed the IRS’s request for payment. As of June 30, 2012, the Company has entered into negotiations with certain parties involved in the claims, but the negotiations are ongoing and no agreements have been reached. The Company cannot reasonably estimate a range of probable losses associated with these claims beyond the maximum possible range of losses of $0 to $5,073.

Table of Contents

Note 17—Income Taxes

The effective tax rate for the three months and six months ended June 30, 2011 and 2012 is different from the federal statutory tax rate primarily as a result of losses for which no tax benefit has been recognized. The Company is required to recognize the impact of a tax position in its financial statements if the position meets the more likely than not threshold 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 six months ended June 30, 2011 and 2012. Further, the Company accrues penalties if the tax position does not meet the minimum statutory threshold to avoid penalties. No penalties have been accrued by the Company. The Company’s unrecognized tax benefits as of June 30, 2012 were unchanged from December 31, 2011.

The Company is subject to taxation in the United States and various state and foreign jurisdictions. The Company’s taxes for 2007 through 2010 are subject to examination by various tax authorities. The Company is no longer subject to United States examination for years before 2008, and state examinations for years before 2007. On July 15, 2010, the IRS sent the Company a letter disallowing approximately $5,073 related to certain claims the Company made from October 1, 2006 to June 30, 2008 under the VETC program and is seeking repayment of such amount. The Company believes its claims were properly made and has appealed the IRS’s request for payment. As of June 30, 2012, the Company has entered into negotiations with certain parties involved in the claims, but the negotiations are ongoing and no agreements have been reached. The Company cannot reasonably estimate a range of probable losses associated with these claims beyond the maximum possible range of losses of $0 to $5,073.

Note 18—Fair Value Measurements

The Company follows authoritative guidance for fair value measurements with respect to assets and liabilities that are measured at fair value on a recurring basis and nonrecurring basis. Under the standard, fair value is defined as the exit price, or the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The standard also establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs market participants would use in valuing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions about the factors market participants would use in valuing the asset or liability developed based upon the best information available in the circumstances. The hierarchy consists of the following three levels: Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities; Level 2 inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and inputs (other than quoted prices) that are observable for the asset or liability, either directly or indirectly; Level 3 inputs are unobservable inputs for the asset or liability. Categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement.

During the six months ended June 30, 2012, the Company’s financial instruments consisted of available-for-sale securities, natural gas futures contracts, debt instruments, a contingent consideration obligation, and its Series I warrants. For securities available-for-sale, the fair value is determined by the most recent trading prices available for each security or for comparable securities, and thus represent Level 2 fair value measurements. The Company uses quoted forward price curves, discounted to reflect the time value of money, to value its natural gas futures contracts which is considered to be a Level 2 fair value measurement. The Company uses an income approach, projecting the financial results for the associated entity, discounted to reflect the time value of money, to value its contingent consideration obligation, which is considered to be a Level 3 fair value measurement. The fair market value of the Company’s debt instruments approximated their carrying values at June 30, 2011 and 2012. The Company uses the Black-Scholes model to value the Series I warrants. The Company believes the best method to approximate the market participant’s view of the volatility of its Series I warrants is to use the implied volatilities of its short-term (i.e. 3 to 9 month) traded options and extrapolate the data over the remaining term of the Series I warrants, which was approximately 3 years and 10 month as of June 30, 2012. This method has been utilized consistently in the periods presented. Given that the extrapolation beyond the term of the short term exchange traded options is not based on observable market inputs for a significant portion of the remaining term of the warrants, the Series I warrants have been classified as a Level 3 fair value determination in the table below.

Table of Contents

The following tables provide information by level for assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2011 and June 30, 2012, respectively:

Description	Balance at December 31, 2011		Level 1		Level 2		Level 3
Assets:
Available-for-sale securities (1):
Certificate of deposits	$	10,000	$	—	$	10,000	$	—
Municipal bonds and notes	19,589		—		19,589		—
Zero coupon bonds	712		—		712		—
Corporate bonds	3,028		—		3,028		—
Liabilities:
Natural gas futures contracts (2)	2,335		—		2,335		—
Contingent consideration obligation (3)	5,978		—		—		5,978
Series I warrants (4)	11,493		—		—		11,493

Description	Balance at June 30, 2012		Level 1		Level 2		Level 3
Assets:
Available-for-sale securities (1):
Certificate of deposits	$	10,021	$	—	$	10,021	$	—
Municipal bonds and notes	22,727		—		22,727		—
Zero coupon bonds and notes	813		—		813		—
Corporate bonds	3,518		—		3,518		—
Liabilities:
Natural gas futures contracts (2)	293		—		293		—
Contingent consideration obligation (3)	1,334		—		—		1,334
Series I warrants (4)	16,100		—		—		16,100

(1) Included in short-term investments in the condensed consolidated balance sheets. See note 5 for further information.

(2) See note 6 for further information.

(3) The current portion is included in accrued liabilities, and the long-term portion is included in other long-term liabilities in the condensed consolidated balance sheets.

(4) Included in other long-term liabilities in the condensed consolidated balance sheets.

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

Liabilities: Series I Warrants	June 30, 2011			June 30, 2012
Balance beginning of year	$	14,148		$	11,493
Total (gain) loss included in earnings	(1,535		)	4,607
Ending Balance	$	12,613		$	16,100

Liabilities: Contingent Consideration	June 30, 2011			June 30, 2012
Balance beginning of year	$	11,200		$	5,978
Total gain included in earnings	(700		)	(4,294		)
Payments	(2,159		)	(350		)
Ending Balance	$	8,341		$	1,334

Valuation processes for Level 3 fair value measurements and sensitivity to changes in significant unobservable inputs

Fair value measurements of liabilities which fall within Level 3 of the fair value hierarchy are determined by the Company’s accounting department, who report to the Company’s Chief Financial Officer. The fair value measurements are compared to those of the prior reporting periods to ensure that changes are consistent with expectations of management based upon the sensitivity and nature of the inputs.

Table of Contents

Contingent Consideration

Pursuant to the terms presented in the Asset Purchase Agreement, the IMW shareholder will earn additional consideration if IMW achieves certain minimum gross profit targets in fiscal years 2011 through 2014. Therefore, the Company estimated the fair value of the contingent consideration using a discounted cash flow model that considers the payout structure based on the following inputs as of June 30, 2012:

Unobservable Input		Range or Weighted Average
Gross profit projection		$9,060 - $32,641
Probability of reaching target gross profit		0.0% - 55.0%
Volatility of gross profit (peer group)		14.1% - 59.1% (simple average 32.9%)
Risk adjusted discount rate		39.0%

Significant changes in any of those inputs in isolation would result in a significant change in the fair value measurement. Generally, a positive change in the assumptions used for the probability of achieving a higher gross profit target threshold would result in a directionally similar change in the estimated fair value of the contingent consideration, and thus an increase in the associated liability. Conversely, an increase in the assumed discount rate would have a directionally opposite impact on the estimated fair value measurement of the contingent consideration, and would result in a decrease in the associated liability.

Series I Warrant Liability

The Company estimated the fair value of its Series I warrant liability using the Black-Scholes Model based on the following inputs as of June 30, 2012:

Unobservable Input		Range or Weighted Average
Current market price of the Company’s common stock		$15.50
Exercise price of the warrant		$12.68
Remaining term of the warrant		3.83
Implied volatility of the Company’s common stock		58.6% – 61.6%
Assumed discount rate		Simple average 0.6%

Significant changes in any of those inputs in the isolation can result in a significant change in the fair value measurement. Generally, a positive change in the market price of the Company’s common stock, and an increase in the volatility of the Company’s common stock, or an increase in the remaining term of the warrant would result in a directionally similar change in the estimated fair value of the Company’s Series I warrants and thus an increase in the associated liability. An increase in the assumed discount rate or a decrease in the positive differential between the warrant’s exercise price and the market price of the Company’s common stock would result in a decrease in the estimated fair value measurement of the Series I warrants and thus a decrease in the associated liability. The Company has not, nor plans to, declare dividends on its common stock, and thus, there is no directionally similar change in the estimated fair value of the warrants due to the dividend assumption.

Non-financial assets

No impairments of long-lived assets measured at fair value on a non-recurring basis have been incurred during the three months or six months ended June 30, 2011 and 2012, respectively. The Company’s use of these nonfinancial assets does not differ from their highest and best use, as determined from the perspective of a market participant.

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

On January 1, 2012, the Company adopted changes issued by the FASB to conform existing guidance regarding fair value measurement and disclosure between GAAP and International Financial Reporting Standards. These changes both clarify the FASB’s intent about the application of existing fair value measurement and disclosure requirements and amend certain principles or requirements for measuring fair value or for disclosing information about fair value measurements. The clarifying changes relate to the application of the highest and best use and valuation premise concepts, measuring the fair value of an instrument classified in a reporting entity’s shareholders’ equity, and disclosure of quantitative information about unobservable inputs used for Level 3 fair value measurements. The amendments relate to measuring the fair value of financial instruments that are managed within a portfolio, application of premiums and discounts in a fair value measurement, and additional disclosures concerning the valuation processes used and sensitivity of the fair value measurement to changes in unobservable inputs for those items categorized as Level 3, a reporting entity’s use of a nonfinancial asset in a way that differs from the asset’s highest and best use, and the categorization by level in the fair value hierarchy for items required to be measured at fair value for disclosure purposes only. Other than the additional disclosure requirements (see note 18), the adoption of these changes had no impact on the condensed consolidated financial statements.

Table of Contents

On January 1, 2012, the Company adopted changes issued by the FASB to the presentation of comprehensive income. These changes give an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The option to present components of other comprehensive income as part of the statement of changes in stockholders’ equity was eliminated. The items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income were not changed. Additionally, no changes were made to the calculation and presentation of earnings per share. Management elected to present the two-statement option. Other than the change in presentation, the adoption of these changes had no impact on the condensed consolidated financial statements.

Note 20—Volumetric Excise Tax Credit (“VETC”)

The Company records its VETC credits as revenue in its condensed consolidated statements of operations as the credits are fully refundable and do not need to offset income tax liabilities to be received. VETC revenues for the three and six month periods ended June 30, 2011 were $4,685 and $8,902, respectively. VETC revenues for the three and six month periods ended June 30, 2012 were $0 for both periods as the legislation expired on December 31, 2011.

Note 21—Subsequent Events

On July 4, 2012, IMW and HSBC amended the IMW Lines of Credit which increased the limit of the operating line of credit to CAD$13,000 from CAD$10,000 (see note 13).

On July 10, 2012, the Company issued the second CHK Note having a principal amount of $50,000 (see note 13).

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, 2011 contained in our 2011 Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 12, 2012, as well as the condensed, consolidated financial statements and notes contained therein. Unless the context indicates otherwise, all references to “Clean Energy,” the “Company,” “we,” “us,” or “our” in this MD&A and elsewhere in this report refer to Clean Energy Fuels Corp. together with its majority and wholly owned subsidiaries.

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 2011 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 2011 Annual Report on Form 10-K pursuant to Instruction 2 to paragraph (b) of Item 303 of Regulation S-K. We undertake no duty to update any of these forward-looking statements after the date of filing of this report to conform such forward-looking statements to actual results or revised expectations, except as otherwise required by law.

We provide natural gas solutions for vehicle fleets primarily in the U.S. and Canada. Our primary business activity is selling compressed natural gas (“CNG”) and liquefied natural gas (“LNG”) vehicle fuel to our customers. We also manufacture and service advanced natural gas fueling compressors and related equipment, build, operate and maintain fueling stations, sell or lease fueling stations to our customers, process and sell renewable natural gas (“RNG”), and provide natural gas vehicle conversions. Our customers include fleet operators in a variety of markets, such as trucking, airports, taxis, refuse hauling, and public transit. In

Table of Contents

April 2008, we opened our first CNG station in Lima, Peru, through our joint venture, Clean Energy del Peru. In August 2008, we acquired 70% of the outstanding membership interests of Dallas Clean Energy LLC (‘DCE”). DCE owns a facility that collects, processes and sells RNG at the McCommas Bluff landfill in Dallas, Texas. On October 1, 2009, we completed our acquisition of BAF Technologies, Inc. (“BAF”), a company that provides natural gas conversions, alternative fuel systems, application engineering, service and warranty support and research and development for natural gas vehicles. On September 7, 2010, we completed the purchase of I.M.W. Industries Ltd. (“IMW”), a company that manufactures and services advanced, non-lubricated natural gas fueling compressors and related equipment. On December 15, 2010, we acquired Wyoming Northstar Incorporated, Southstar LLC, and M&S Rental, LLC (collectively “Northstar”), a provider of design, engineering, construction and maintenance services for LNG and liquefied to compressed natural gas (“LCNG”) fueling stations.

Overview

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

Sources of revenue. We generate a significant amount of our revenue from selling CNG and LNG, and commencing on September 7, 2010, also from selling advanced natural gas fueling compressors and related equipment and maintenance services through our subsidiary, IMW. A significant portion of our revenue is also earned by designing and constructing and selling natural gas fueling stations, selling natural gas vehicle conversions through our wholly owned subsidiary, BAF, providing fueling station operations and maintenance services to our customers, and selling pipeline quality RNG produced by our DCE joint venture. We also generate limited revenue by providing the financing for our customers’ natural gas vehicle purchases.

Key operating data. In evaluating our operating performance, our management focuses primarily on: (1) the amount of CNG and LNG gasoline gallon equivalents delivered (which we define as (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 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 RNG produced and sold as pipeline quality natural gas by DCE), (2) our gross margin (which we define as revenue minus cost of sales), and (3) net income (loss) attributable to us. 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 2011 Annual Report on Form 10-K for the year ended December 31, 2011, presents our key operating data for the years ended December 31, 2009, 2010, and 2011 and for the three and six months ended June 30, 2011 and 2012:

Gasoline gallon equivalents delivered (in millions)	Year Ended December 31, 2009			Year Ended December 31, 2010			Year Ended December 31, 2011			Three Months Ended June 30, 2011			Three Months Ended June 30, 2012			Six Months Ended June 30, 2011			Six Months Ended June 30, 2012
CNG	67.9			81.4			101.8			25.6			32.2			48.3			61.2
RNG	6.4			7.4			6.7			1.7			2.0			3.2			4.1
LNG	26.7			33.9			47.1			11.9			14.4			23.2			27.0
Total	101.0			122.7			155.6			39.2			48.6			74.7			92.3
Operating data
Gross margin	$	48,582		$	69,945		$	76,033		$	18,689		$	21,312		$	37,027		$	39,060
Net income (loss)	(33,249		)	(2,516		)	(47,633		)	(5,619		)	(11,294		)	(15,372		)	(43,199		)

Key trends in 2009, 2010, 2011 and the first six months of 2012. According to the Energy Information Administration, demand for natural gas fuels in the United States increased by approximately 26% during the period January 1, 2009 through December 31, 2011. 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 196 at December 31, 2009 to 313 at June 30, 2012 (a 59.7% increase). Included in this number are all of the CNG and LNG fueling stations we own, maintain or with which we have a fueling supply contract. The amount of CNG, RNG and LNG gasoline gallon equivalents we delivered from 2009 to 2011 increased by 54%. The increase in gasoline gallon equivalents delivered was the primary contributor to increased revenues during 2009, 2010 and 2011. In addition, in 2011, we also benefitted from increased revenues from compressor sales and fueling station installations as a result of our acquisitions of IMW and Northstar, which occurred during the fourth quarter of 2010.

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 in 2009 and 2010. In 2011, the cost of sales related to compressors sold through IMW and fueling station installations performed by Northstar also contributed to the increase.

Table of Contents

Since the last half of 2009, we have experienced reduced margins in certain markets, particularly in the municipal transit and refuse sector. The reduction in margins is primarily a result of increased competition and sales agreements with larger entities that have greater pricing leverage. Also, in many cases, our agreements with our customers, including governmental agencies, are subject to a competitive bidding process and we have been required to reduce our prices to maintain our contracts as they come up for bid. In addition, in May and June of 2009, we acquired four compressed natural gas operations and maintenance services contracts with municipal transit agencies, and in 2010 and 2011, we won several contracts with a transit agency in California that have significant volume but smaller margins than we typically generate on our fuel sales. As a result of all of these factors, the overall average margin on our fuel sales across our business decreased sequentially in 2010 and 2011.

We believe that our margins on fuel sales will improve in the future to the extent we are successful in increasing our retail CNG and LNG fueling operations, which is where we earn our highest margins. If our retail CNG and LNG fueling operations do not grow, we may experience further reduced margins. We may also lose contracts with governmental customers if we are unwilling or unable to reduce our prices or lose in the competitive bidding process, which would reduce our volumes. We will need to increase our business with non-government entities to replace volumes lost in competitive bid procurements when we are not successful in retaining the contracts.

During 2011 and the first six months of 2012, prices for oil, gasoline, and diesel fuel were generally substantially higher than the price for natural gas. Oil hit a high of $107.07 in February 2012 and settled at $84.96 per barrel on June 30, 2012. In California, average retail prices for gasoline have increased from $3.68 per gallon in January 2012 to $3.94 per gallon at June 30, 2012, and the average retail price for diesel fuel hit a high of $4.48 per diesel gallon in March 2012 and was $3.91 per diesel gallon at June 30, 2012. Higher gasoline and diesel prices typically improve our margins on fuel sales to the extent we price fuel at a discount to gasoline or diesel. During this time period, the NYMEX price for natural gas fluctuated from a high of $3.08 per MMbtu in January 2012 to $2.42 per MMbtu at June 30, 2012. The average retail sales price of our CNG fuel sold in the Los Angeles metropolitan area ranged from $2.60 for the month of January 2011 to $2.80 for the month of June 2012. The average retail sales price of our LNG fuel sold in the Los Angeles metropolitan area ranged from $2.50 for the month of January 2011 to $2.90 at June 30, 2012.

Anticipated future trends. We anticipate that, over the long term, the prices for gasoline and diesel will continue to be significantly 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 large part on the growth in United States natural gas production.

The 2012 Annual Outlook early release from the United States Energy Information Administration (“EIA”) states that total marketed production of natural gas grew by an estimated 4.5 Bcf/d (7.4%) in 2011, the largest year-over-year volumetric increase in history. This strong growth was driven in large part by increases in shale gas production. EIA expects production to grow by 1.4 Bcf/d (2.2%) in 2012 and 0.7 Bcf/d (1.0%) in 2013 as low natural gas prices reduce new drilling plans and consumption is estimated to grow at a moderate pace. In the face of continued low spot and future prices, as well as record high storage levels, drillers appear to have started reducing new production plans for 2012. According to Baker Hughes, the natural gas rig count has fallen to 809 as of December 29, 2011, from a 2011 high of 936 in mid-October. However, high initial production rates from new wells, associated natural gas production from oil drilling, and a backlog of uncompleted or unconnected wells contribute to the forecast of further production increases in 2012 and 2013, albeit at lower rates than 2011.

The preliminary 2012 Annual Energy Outlook report from the EIA estimates that shale gas could represent 49% (13.6 tcf) of United States natural gas production by the year 2035, up from the 14% and 23% (5 tcf) of domestic natural gas produced in 2009 and 2010, respectively. The EIA estimates that based upon 2010 consumption levels, that there is enough available shale gas to satisfy demand for the next 100 years. The primary reason for the availability of additional natural gas is the increased successful use of recent shale drilling technology and continued drilling in shale plays with high concentrations of natural gas liquids and crude oil, which have a higher energy value than dry natural gas.

Hydraulic fracturing (commonly called “fracking” or “hydrofracking”) is a technique in which water, sand and a small amount of chemicals are pumped into the well to unlock the hydrocarbons trapped in shale formations by opening cracks (fractures) in the rock and allowing natural gas to flow from the shale into the well. When used in conjunction with horizontal drilling, hydraulic fracturing enables gas producers to extract shale gas at reasonable cost. Horizontal drilling is an enhanced oil recovery or gas recovery method. A horizontal well is commonly defined as any well in which the lower part of the well bore parallels the oil zone. The benefits of horizontal wells include the avoidance of drawdown-related problems such as water/gas coning, and extension of wells by means of multiple drain holes. Without these techniques, natural gas does not flow to the well rapidly, and commercial quantities cannot be produced from shale because the natural gas would not flow from the formation at high enough rates to justify the cost of drilling. There have been recent efforts to place new regulatory requirements on the production of natural gas by hydraulic fracturing, and any regulations that make it more expensive or unprofitable to produce natural gas through hydraulic fracturing could lead to reduced natural gas supply and increased natural gas prices.

Table of Contents

According to the 2010 BP Statistical Review of World Energy, on a global basis, the ratio of proven natural gas reserves to 2009 natural gas production was 37% greater than the ratio of proven crude oil reserves to 2009 crude oil production. This analysis suggests significantly greater long term availability of natural gas than crude oil based on current consumption. Based on this report, we believe that there is a significant worldwide supply of natural gas relative to crude oil.

We believe there will be significant growth in the consumption of natural gas as a vehicle fuel among vehicle fleets, and our goal is to capitalize on this trend and enhance our leadership position as this market expands. With our recent acquisitions of IMW and Northstar, we are now a fully integrated provider of advanced compression technology, station-building and fueling. We also anticipate expanding our sales of CNG and LNG in the other markets in which we operate, including trucking, refuse hauling, airports, taxis and public transit. Consistent with the anticipated growth of our business, we also expect that our operating costs and capital expenditures will increase, primarily from the anticipated expansion of our station network or LNG production capacity, as well as the logistics of delivering more CNG and LNG to our customers. We also anticipate that we will continue to seek to acquire assets and/or businesses that are in the natural gas fueling infrastructure or RNG 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.

We anticipate the commercial roll-out of natural gas engines that are well-suited for the United States heavy-duty trucking market, together with the economic and environmental benefits of natural gas fuel, will result in increased adoption of natural gas fueled trucks by the United States trucking industry. Heavy-duty trucks in the United States are generally high-volume consumers of vehicle fuel, and we believe many use 20,000 gallons or more per year. We therefore believe that this market may become our largest market. As a result, we have made a significant commitment of capital and other resources to build a nationwide network of LNG truck fueling stations, which we refer to as “America’s Natural Gas Highway,” or “ANGH,” on the interstate highway system and in major metropolitan areas that will enable natural gas fueled freight trucking coast to coast and border to border within the 48 continental states. We expect the first phase of ANGH to include approximately 150 fueling stations, with approximately 70 stations anticipated to be open in 33 states by the end of 2012, and the balance in 2013. We expect that many ANGH stations will be co-located at Pilot-Flying J Travel Centers already serving goods movement trucking.

Many governmental entities, which represented approximately 40% of our revenues from January 1, 2011 through June 30, 2012, 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. They may also be compelled to reduce public transportation and services, or the prices they pay for these services, which would negatively affect our business.

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

Our business plan calls for approximately $128.2 million in capital expenditures from July 1, 2012 through the end of 2012, primarily related to construction of new fueling stations, including ANGH stations, expanding our California LNG plant, expanding and building landfill gas processing plants, and the purchase of LNG trailers. We may also elect to invest additional amounts in companies or assets in the natural gas fueling infrastructure, services and production industries, including RNG production. We will need to raise additional capital as necessary to fund any capital expenditures or investments that we cannot fund through available cash or cash generated by operations. The timing and necessity of any future capital raise will depend on our rate of new station construction and potential merger or acquisition activity. For more information, see “Liquidity and Capital Resources” and “Capital Expenditures” below. We may not be able to raise capital on terms that are favorable to existing stockholders or at all. Any inability to raise capital may impair our ability to invest in new stations, develop natural gas fueling infrastructure and invest in strategic transactions or acquisitions, and may reduce our ability to grow our business and generate increased revenues.

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

Table of Contents

Operations

We generate revenues principally by selling CNG and LNG and providing O&M services to our vehicle fleet customers. For the six months ended June 30, 2012, CNG and RNG (together) represented 71% and LNG represented 29% 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 RNG produced by our joint venture subsidiary DCE, sales of natural gas vehicles by our wholly owned subsidiary BAF, sales of advanced natural gas fueling compressors and related equipment and maintenance services through IMW, and sales of LNG and LCNG fueling station design, construction and O&M services through Northstar. Substantially all of our operating and maintenance revenues are generated from CNG stations, as owners of LNG stations typically operate and maintain their own stations. Substantially all of our station sale and leasing revenues have been generated from CNG stations.

CNG Sales

We sell CNG through fueling stations located on our customers’ properties and through our network of public access fueling stations. At these CNG fueling stations, we procure natural gas from local utilities or brokers under standard, floating-rate arrangements and then compress and dispense it into our customers’ vehicles. Our CNG sales are made primarily through contracts with our fleet customers. Under these contracts, pricing is determined primarily on an index-plus basis, which is calculated by adding a margin to the local index or utility price for natural gas. CNG sales revenues based on an index-plus methodology increase or decrease as a result of an increase or decrease in the price of natural gas. We also sell a small amount of CNG under fixed-price contracts. We will continue to offer fixed price contracts, as appropriate, and consistent with our natural gas hedging policy. 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 LNG to fleet customers, who typically own and operate their fueling stations. Increasingly, we also sell LNG to fleet and other customers at our public-access LNG stations and for non-vehicle use. During 2012, we procured 40% of our LNG from third-party producers, and we produced the remainder of the LNG at our liquefaction plants in Texas and California. For LNG that we purchase from third parties, we may enter into “take or pay” contracts that require us to purchase minimum volumes of LNG at index-based rates. We deliver LNG via our fleet of 58 tanker trailers to fueling stations, where it is stored and dispensed in liquid form into vehicles. We sell LNG principally through supply contracts that are priced on either a fixed-price or index-plus basis. LNG sales revenues based on an index-plus methodology increase or decrease as a result of an increase or decrease in the price of natural gas. We will continue to offer fixed price contracts as appropriate and consistent with our natural gas hedging policy. Our LNG contracts provide that we charge our customers periodically based on the volume of LNG supplied. We also sell LNG 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.

America’s Natural Gas Highway

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

Government Incentives

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

On July 15, 2010, the IRS sent us a letter (i) disallowing approximately $5.1 million related to certain claims we made from October 1, 2006 to June 30, 2008 under the Volumetric Excise Tax Credit program, and (ii) seeking repayment of such amount. We believe our claims were properly made and are contesting the IRS’s determination. As of June 30, 2012, we have entered into negotiations with certain parties involved in the claims, but the negotiations are ongoing and no agreements have been reached. We cannot reasonably estimate a range of probable losses associated with these claims beyond the maximum possible range of losses of $0 to $5.1 million.

Table of Contents

Operation and Maintenance

We generate a portion of our revenue from operation and maintenance agreements for CNG and LNG 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 delivered.

Station Construction

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

On December 15, 2010, we completed the purchase of Northstar, an entity that provides design, engineering, construction and maintenance services for LNG and LCNG fueling stations. For the six months ended June 30, 2011 and 2012, Northstar contributed approximately $5.7 million and $2.6 million, respectively, to our revenue.

Vehicle Acquisition and Finance

In 2006, we commenced offering vehicle finance services for some of our customers’ purchases of natural gas vehicles or the conversion of their existing gasoline or diesel powered vehicles to operate on natural gas. We loan to certain qualifying customers a portion of, and on occasion up to 100% of, the purchase price of their natural gas vehicles. We may also lease vehicles in the future. Where appropriate, we apply for and receive state and federal incentives associated with natural gas vehicle purchases and pass these benefits through to our customers. We may also secure vehicles to place with customers or pay deposits with respect to such vehicles prior to receiving a firm order from our customers, which we may be required to purchase if our customer fails to purchase the vehicle as anticipated. Through June 30, 2012, we have not generated significant revenue from vehicle financing 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 RNG from the McCommas Bluff landfill located in Dallas, Texas. For the six months ended June 30, 2011 and 2012, DCE generated approximately $5.9 million and $7.2 million, respectively, in revenue from sales of RNG, all of which is included in our condensed consolidated statements of operations.

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

DCE retains the right to reserve from the Shell Gas Sale Agreement up to 500 MMBtus per day of RNG for sale as a vehicle fuel. To the extent that DCE produces volumes of RNG 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. DCE may not produce or be able to sell up to the maximum volumes called for under the agreement. DCE’s ability to produce RNG 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 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, and consequently may reduce DCE’s sales of RNG during the expansion and upgrade period. The expansion and upgrade work is anticipated to be completed in the fourth quarter of 2012.

The sale price for the gas under the Shell Gas Sale Agreement is fixed. The sale price for the gas represents a substantial premium to the current prevailing prices for natural gas at August 6, 2012.

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

Table of Contents

In November 2010, our subsidiary Canton Renewables, LLC (“Canton Renewables”), signed a Gas Sale and Purchase Agreement that grants Canton Renewables the right to produce RNG at a landfill owned and operated by Republic Services in Canton, Michigan. The landfill gas facility is under construction and is expected to be completed and operational in the summer of 2012. Canton Renewables has executed an agreement with an affiliate of the local gas utility that will enable Canton Renewables to inject the RNG produced into the local gas transmission system and transport it to the interstate pipeline, where it may be distributed for use in power generation or as a low-carbon, renewable vehicle fuel. We have entered into a ten-year fixed-price sale contract for the majority of the RNG we expect this landfill gas facility to produce; provided that such sale contract may be terminated by either party with prior written notice if a governmental authority makes a final determination or adopts a law, ruling or regulation that would result in the RNG subject to the agreement no longer being able, when combusted, to generate RPS eligible renewable energy.

We have also entered into what we believe to be a first of its kind transaction to sell renewable identification number credits (commonly referred to as “RINs”) we expect to generate under the Federal Renewable Standard Phase II by selling RNG in the vehicle fuels market.

Vehicle Conversions

On October 1, 2009, we completed our acquisition 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. BAF’s vehicle conversions include taxis, vans, pick-up trucks and shuttle buses. BAF utilizes advanced natural gas system integration technology and has certified NGVs under both EPA and CARB standards achieving Super Ultra Low Emission Vehicle emissions. We generate revenues through the sale of natural gas vehicles that have been converted to run on natural gas by BAF. The majority of BAF’s revenue during 2010 and 2011 was derived from sales of converted natural gas service vans to AT&T. During the first six months of 2011 and 2012, BAF contributed approximately $12.6 million and $14.9 million, respectively, to our revenue.

Natural Gas Fueling Compressors

On September 7, 2010, we completed our purchase of IMW. IMW manufactures and services advanced, non-lubricated natural gas fueling compressors and related equipment for the global natural gas fueling market. IMW is headquartered near Vancouver, British Columbia, has other manufacturing facilities near Shanghai, China and in Ferndale, Washington, and has sales and service offices in Bangladesh, Colombia, Peru and the United States. For the six months ended June 30, 2011 and 2012, IMW contributed approximately $30.8 million and $27.7 million, respectively, to our revenue.

Volatility of Earnings and Cash Flows

During 2009, 2010, 2011 and the first six months of 2012, our futures contracts qualified for hedge accounting, so we had no derivative gains or losses recognized in our consolidated statements of operations for these periods. In accordance with our natural gas hedging policy, we plan to structure all futures contracts as cash flow hedges under the applicable derivative accounting guidance, but we cannot be certain that they will qualify. See “Risk Management Activities” below. If the futures contracts do not qualify for hedge accounting, we could incur significant increases or decreases in our earnings based on fluctuations in the market value of the contracts from period to period.

Additionally, we are required to maintain a margin account to cover losses related to our natural gas futures contracts. Futures contracts are valued daily, and if our contracts are in loss positions at the end of a trading day, our broker will transfer the amount of the losses from our margin account to a clearinghouse. If at any time the funds in our margin account drop below a specified maintenance level, our broker will issue a margin call that requires us to restore the balance. Consequently, these payments could significantly impact our cash balances. At June 30, 2012, we had paid $3.6 million in margin deposits, which are included in prepaid expenses and other current assets and notes receivable and other long-term assets in our balance sheet. On July 6, 2012, we received $3.0 million back on our margin deposits.

The decrease in the value of our futures positions and any corresponding margin deposits required thereon could significantly impact our financial position in the future.

Volatility of Earnings Related to Series I Warrants

Beginning January 1, 2009, under 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. We have recognized a loss (gain) of $(1.5) million and $4.6 million related to recording the estimated fair value changes of our Series I warrants in the six months ended June 30, 2011 and 2012, respectively. See note 18 to our condensed consolidated financial statements contained

Table of Contents

elsewhere herein. Our earnings or loss per share may be materially affected by future gains or losses we are required to recognize as a result of valuing our Series I warrants. On November 10, 2010, 1,183,712 of the Series I warrants were exercised. As of June 30, 2012, 2,130,682 of the Series I warrants remained outstanding.

Volatility of Earnings Related to Contingent Consideration

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

If the anticipated results of IMW increase or decrease during future periods, we may be required to recognize material losses or gains based on the valuation of the increased or decreased consideration due to the former IMW shareholder. During the first six months of 2012, we recognized a gain of $4.3 million related to the estimated change in the value of the IMW contingent consideration. Our earnings or loss per share may be materially affected by future gains or losses we are required to recognize as a result of changes in the estimated fair value of the contingent consideration amount.

Debt Compliance

In connection with our acquisition of IMW, we entered into a credit agreement with HSBC that requires IMW to comply with certain financial covenants (see note 13 to our condensed consolidated financial statements). 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 would be due and payable. IMW was in compliance with these covenants as of June 30, 2012.

The Indenture and the Loan Agreement DCEMB entered into as part of issuing its Revenue Bonds, as defined and disclosed in note 13 to our condensed consolidated financial statements, each have certain non-financial debt covenants with which DCEMB must comply. As of June 30, 2012, DCEMB was in compliance with these debt covenants.

The Loan Agreement we entered into as part of issuing the CHK Notes, as defined and discussed in note 13 to our condensed consolidated financial statements, has certain non-financial debt covenants with which we must comply. As of June 30, 2012, we were in compliance with these debt covenants.

The Convertible Note Purchase Agreements we entered into as part of issuing the SLG Notes, as defined and discussed in note 13 to our condensed consolidated financial statements, have certain non-financial debt covenants with which we must comply. As of June 30, 2012, we were in compliance with these covenants.

Some of our natural gas fuel sales contracts require us to sell LNG or CNG to our customers at a fixed price. These contracts expose us to the risk that the price of natural gas may increase above the natural gas cost component included in the price at which we are committed to sell gas to our customers.

In an effort to mitigate the volatility of our earnings related to our futures contracts and to reduce our risk related to fixed price sales contracts, we operate under a natural gas hedging policy pursuant to which we only purchase futures contracts to hedge our exposure to variability in expected future cash flows related to a particular fixed price contract or bid. Subject to the conditions set forth in the policy, we purchase futures contracts in quantities reasonably expected to effectively hedge our exposure to cash flow variability related to such fixed price sales contracts entered into after the date of the policy. Unless otherwise agreed in advance by the board of directors and the derivative committee, we will conduct our futures activities and enter into fixed price sales contracts only in accordance with the natural gas hedging policy, a complete copy of which, as amended effective May 29, 2008, was filed as Exhibit 99.1 to our Form 8-K filed with the SEC on June 20, 2008. The summary of the policy described above does not purport to be complete and is qualified in its entirety by reference to the copy of the policy previously filed.

Due to the restrictions of our revised hedging policy, we expect to offer fewer fixed price sales contracts to our customers. If we do offer a fixed price sales contract, we anticipate including a price component that would cover our estimated cash requirements over the duration of the underlying futures contracts. The amount of this price component will vary based on the anticipated volume and the natural gas price component to be covered under the fixed price sales contracts.

Table of Contents

Risk Management Activities

Our risk management activities, including our revised natural gas hedging policy, are discussed elsewhere in this quarterly report on Form 10-Q and in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) of our 2011 Annual Report on Form 10-K. For the quarter ended June 30, 2012, there were no material changes to our risk management activities.

Critical Accounting Policies

For the six months ended June 30, 2012, 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 2011 Annual Report on Form 10-K.

Recently Issued Accounting Pronouncements

For a description of recently issued accounting pronouncements, see note 19 to our condensed consolidated financial statements contained elsewhere herein.

Results of Operations

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2012		2011		2012
Statement of Operations Data:
Revenue:
Product revenues	89.0	%	82.6	%	89.3	%	86.1	%
Service revenues	11.0		17.4		10.7		13.9
Total revenues	100.0		100.0		100.0		100.0
Operating expenses:
Cost of sales:
Product cost of sales	67.8		62.6		67.5		66.6
Service cost of sales	5.1		6.9		5.0		6.1
Derivative (gains) losses on Series I warrant valuation	(7.0	)	(12.7	)	(1.1	)	3.2
Selling, general and administrative	31.4		39.9		29.5		36.8
Depreciation and amortization	11.0		12.8		11.0		11.9
Total operating expenses	108.3		109.5		111.9		124.6
Operating income (loss)	(8.3	)	(9.5	)	(11.9	)	(24.6	)
Interest income (expense), net	(2.2	)	(4.7	)	(1.7	)	(4.9	)
Other income (expense), net	0.3		(1.7	)	0.6		(0.2	)
Income from equity method investments	0.2		0.1		0.2		0.1
Income (loss) before income taxes	(10.0	)	(15.8	)	(12.8	)	(29.6	)
Income tax (expense) benefit	1.7		(0.2	)	1.4		(0.3	)
Net income (loss)	(8.3	)	(16.0	)	(11.4	)	(29.9	)
Loss (income) attributable to noncontrolling interest	0.2		(0.1	)	(0.1	)	(0.1	)
Net income (loss) attributable to Clean Energy Fuels Corp.	(8.1	)	(16.1	)	(11.5	)	(30.0	)

Three Months Ended June 30, 2012 Compared to Three Months Ended June 30, 2011

Revenue. Revenue increased by $0.7 million to $69.8 million in the three months ended June 30, 2012, from $69.1 million in the three months ended June 30, 2011. A portion of this increase was the result of an increase in the number of gallons delivered between periods from 39.2 million gasoline gallon equivalents to 48.6 million gasoline gallon equivalents. The increase in volume was primarily from an increase in CNG sales of 6.6 million gallons. Our net increase in CNG volume was primarily from nine new refuse customers, four new airport customers, two new transit customers, one new station from an existing transit customer, three new trucking customers, and one new public customer, which together accounted for 4.4 million gallons of the CNG volume increase. We also experienced an increase of 2.2 million gallons in CNG volume between periods from our existing airport, transit and refuse customers, combined with the volume growth from our share of our joint venture in Peru. Further, we also experienced an increase of 2.5 million gallons in LNG volume between periods, which was primarily due to a combination of 1.2 million gallons from Northstar O&M services and 1.0 million gallons from six new trucking, transit and refuse customers. We experienced an increase in our RNG sales (through our 70% share of the RNG sales at DCEMB) of 0.3 million gallons between periods due to increased RNG production at DCEMB’s facility. We experienced a $2.2 million increase, excluding Northstar, in

Table of Contents

station construction revenues between periods, primarily due to the completion of two new CNG stations for two new refuse customers. Also contributing to the revenue increase between periods were $2.1 million of low carbon fuel standard credits (“LCFS”) that we recognized due to the lifting, during the three months ended June 30, 2012, of a federal court injunction that had prohibited enforcement of the California Low Carbon Fuel Standard. These increases were offset by the decrease in our effective price per gallon that we charged to our customers between periods. Our effective price per gallon was $0.80 in the three months ended June 30, 2012, which represents a $0.07 per gallon decrease from $0.87 per gallon in the three months ended June 30, 2011. The decrease was due to a combination of lower natural gas prices in the second quarter of 2012, upon which we base a portion of our pricing to our customers, and a higher percentage of O&M contracts in the second quarter of 2012, which generate less revenue per gallon than contracts where we supply the natural gas commodity. Northstar’s revenues decreased by $1.6 million between periods as they were primarily focused on building LNG stations for our America’s Natural Gas Highway during the three months ended June 30, 2012. Revenue attributable to VETC also decreased between periods as we did not record any revenue related to fuel tax credits in the second quarter of 2012 because the fuel tax credits expired on December 31, 2011, and we recorded $4.7 million of revenue related to fuel tax credits during the second quarter of 2011. In addition, the increase in revenue between periods was offset by $2.5 million due to decreased sales of natural gas vehicle equipment in the second quarter of 2012.

Cost of sales. Cost of sales decreased by $1.9 million to $48.5 million in the three months ended June 30, 2012, from $50.4 million in the three months ended June 30, 2011. Our cost of sales primarily decreased between periods as a result of a decrease in our effective cost per gallon between periods. Our effective cost per gallon decreased by $0.15 per gallon, from $0.62 per gallon to $0.47 per gallon, in the three months ended June 30, 2012. This decrease was the result of lower natural gas costs and a higher percentage of O&M contracts in the second quarter of 2012 that are included in our volume totals but do not increase our cost of sales amount significantly as we do not pay for the natural gas consumed at the properties. Northstar contributed $1.1 million to our decreased cost of sales between periods. We also experienced a $1.2 million decrease in costs related to BAF’s vehicle equipment sales between periods as BAF’s sales of natural gas vehicle equipment decreased. These decreases were offset by a $4.5 million increase in costs as a result of delivering more volume to our customers and a $2.0 million increase, excluding Northstar, in station construction costs between periods.

Derivative (gain) loss on Series I warrant valuation. Derivative gain increased by $4.1 million to $8.9 million in the three months ended June 30, 2012, from $4.8 million in the three months ended June 30, 2011. These amounts represent the non-cash impact with respect to valuing our outstanding Series I warrants based on our mark-to-market accounting for the warrants during the periods. (See note 18 to our condensed consolidated financial statements contained elsewhere herein.)

Selling, general and administrative. Selling, general and administrative expenses increased by $6.2 million to $27.9 million in the three months ended June 30, 2012, from $21.7 million in the three months ended June 30, 2011. The most significant increase was our salaries and benefits amount increasing by $3.0 million between periods due to our employee headcount increasing from 829 at June 30, 2011 to 1,110 at June 30, 2012. We also experienced a $2.6 million increase in consulting, employee recruiting, business insurance, rent and occupancy, research and development, travel and entertainment, and office supplies expenses related to our continued business growth. Stock based compensation expense also increased between periods by $2.2 million. These increases were offset by a $1.6 million gain related to a decrease in the estimated fair value of the IMW contingent consideration liabilities between periods.

Depreciation and amortization. Depreciation and amortization increased by $1.3 million to $8.9 million in the three months ended June 30, 2012, from $7.6 million in the three months ended June 30, 2011. This increase was primarily due to additional depreciation expense in the three months ended June 30, 2012 related to increased property and equipment balances between periods, primarily related to our expanded station network. In addition, our amortization expense for the three month period ended June 30, 2012 includes increased amortization expense related to our ServoTech acquisition that we completed on April 30, 2012.

Interest income (expense), net. Interest income (expense), net, increased by $1.8 million to $3.3 million of expense for the three months ended June 30, 2012, from $1.5 million of expense for the three months ended June 30, 2011. This increase was primarily the result of an increase in interest expense due to the $200 million of convertible notes we issued in July and August of 2011 (see note 13 to our condensed consolidated financial statements for a full description of our outstanding debt).

Other income (expense), net. Other income (expense), net, decreased by $1.4 million to $1.2 million of expense for the three months ended June 30, 2012, compared to income of $0.2 million for the three months ended June 30, 2011. This decrease was primarily due to foreign currency exchange rate changes between periods on our IMW purchase notes.

Income (loss) from equity method investment. During the three months ended June 30, 2012, we recorded $0.1 million of equity income from our 49% interest in our Peruvian joint venture, compared to $0.2 million during the second quarter of 2011.

Table of Contents

Loss (income) of noncontrolling interest. During the three months ended June 30, 2012, we recorded $0.1 million for the noncontrolling interest in the net income of DCEMB, compared to $0.1 million for the noncontrolling interest in the net loss of DCEMB for the three months ended June 30, 2011. The noncontrolling interest represents the 30% interest of our joint venture partner.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Revenue. Revenue increased by $9.0 million to $143.5 million in the six months ended June 30, 2012, from $134.5 million in the six months ended June 30, 2011. A portion of this increase was the result of an increase in the number of gallons delivered between periods from 74.7 million gasoline gallon equivalents to 92.3 million gasoline gallon equivalents. The increase in volume was primarily from an increase in CNG sales of 12.9 million gallons. Our net increase in CNG volume was primarily from 11 new refuse customers, seven new airport customers, two new transit customers, one new station from an existing transit customer, three new trucking customers, and one new public customer, which together accounted for 7.1 million gallons of the CNG volume increase. We also experienced an increase of 5.8 million gallons in CNG volume between periods from our existing airport, transit and refuse customers, combined with the volume growth from our share of our joint venture in Peru. Further, we experienced an increase of 3.8 million gallons in LNG volume between periods, which was primarily due to a combination of 1.9 million gallons from Northstar O&M services and 1.6 million gallons from six new trucking, transit and refuse customers. We experienced an increase in our RNG sales (through our 70% share of the RNG sales at DCEMB) of 0.9 million gallons due to increased RNG production at DCEMB’s facility. We experienced a $9.2 million increase, excluding Northstar, in station construction revenues between periods, primarily due to the completion of five new CNG stations for new trucking customers, one new CNG station for an existing trucking customer, three new CNG stations for new refuse customers, two CNG station upgrades for two existing refuse customers, one new CNG station for an existing refuse customer, one new CNG station for a transit customer, one CNG station upgrade for an existing transit customer, and one new CNG station for a new airport customer. Revenue also increased by $2.2 million between periods due to increased sales of natural gas vehicle equipment and emission control services by BAF. Also contributing to the revenue increase between periods were $2.1 million of LCFS credits that we recognized due to the lifting, during the six months ended June 30, 2012, of a federal court injunction that had prohibited enforcement of the California Low Carbon Fuel Standard. These increases were offset by the decrease in our effective price per gallon that we charged to our customers between periods. Our effective price per gallon was $0.82 in the six months ended June 30, 2012, which represents a $0.04 per gallon decrease from $0.86 per gallon in the six months ended June 30, 2011. The decrease was due to a combination of lower natural gas prices in the first six months of 2012, upon which we base a portion of our pricing to our customers, and a higher percentage of O&M contracts in the first six months of 2012, which generate less revenue per gallon than contracts where we supply the natural gas commodity. Revenue attributable to VETC also decreased between periods as we did not record any revenue related to fuel tax credits in the first six months of 2012 because the fuel tax credits expired on December 31, 2011 and we recorded $8.9 million of revenue related to fuel tax credits during the first six months of 2011. IMW and Northstar each contributed $3.1 million, respectively, to our decreased revenue between periods.

Cost of sales. Cost of sales increased by $7.0 million to $104.4 million in the six months ended June 30, 2012, from $97.4 million in the six months ended June 30, 2011. Our cost of sales primarily increased between periods as a result of delivering more volume to our customers. We experienced a $9.8 million increase, excluding Northstar, in station construction costs between periods. We also experienced a $1.8 million increase in costs related to BAF’s vehicle equipment sales and emission control services between periods as BAF’s sales of natural gas vehicle equipment increased. These increases were offset by the decrease in our effective cost per gallon of $0.11 per gallon, from $0.62 per gallon to $0.51 per gallon, in the six months ended June 30, 2012. This decrease was the result of lower natural gas costs and a higher percentage of O&M contracts in the first six months of 2012 that are included in our volume totals but do not increase our cost of sales amount significantly as we do not pay for the natural gas consumed at the properties. IMW and Northstar contributed $3.8 million and $1.9 million, respectively, to our decreased cost of sales between periods.

Derivative (gain) loss on Series I warrant valuation. Derivative (gain) loss decreased by $6.1 million to a $4.6 million loss in the six months ended June 30, 2012, from a $1.5 million gain in the six months ended June 30, 2011. These amounts represent the non-cash impact with respect to valuing our outstanding Series I warrants based on our mark-to-market accounting for the warrants during the periods (see note 18 to our condensed consolidated financial statements contained elsewhere herein).

Selling, general and administrative. Selling, general and administrative expenses increased by $13.1 million to $52.8 million in the six months ended June 30, 2012, from $39.7 million in the six months ended June 30, 2011. The most significant increase was our salaries and benefits amount increasing by $6.5 million between periods due to our employee headcount increasing from 829 at June 30, 2011 to 1,110 at June 30, 2012. We also experienced a $6.7 million increase in consulting, employee recruiting, business insurance, rent and occupancy, research and development, travel and entertainment, and office supplies expenses related to our continued business growth. Stock based compensation expense also increased between periods by $3.5 million. These increases were offset by a $3.6 million gain related to a decrease in the estimated fair value of the IMW contingent consideration liabilities between periods.

Table of Contents

Depreciation and amortization. Depreciation and amortization increased by $2.3 million to $17.1 million in the six months ended June 30, 2012, from $14.8 million in the six months ended June 30, 2011. This increase was primarily due to additional depreciation expense in the six months ended June 30, 2012 related to increased property and equipment balances between periods, primarily related to our expanded station network. In addition, our amortization expense for the six month period ended June 30, 2012 includes increased amortization expense related to our ServoTech acquisition that we completed on April 30, 2012.

Interest income (expense), net. Interest income (expense), net, increased by $4.7 million to $7.0 million of expense for the six months ended June 30, 2012, from $2.3 million for the six months ended June 30, 2011. This increase was primarily the result of an increase in interest expense due to the $200 million of convertible notes we issued in July and August of 2011 (see note 13 to our condensed consolidated financial statements for a full description of our outstanding debt).

Other income (expense), net. Other income (expense), net, decreased by $1.1 million to $0.3 million of expense for the six months ended June 30, 2012, compared to income of $0.8 million for the six months ended June 30, 2011. This decrease was primarily due to foreign currency exchange rate changes between periods on our IMW purchase notes.

Income from equity method investments. During the six months ended June 30, 2012, we recorded $0.2 million of equity income from our 49% interest in our Peruvian joint venture, compared to $0.4 million during the first six months of 2011.

Loss (income) of noncontrolling interest. During the six months ended June 30, 2012 and 2011, we recorded $0.2 million for the noncontrolling interest in the net income of DCEMB. The noncontrolling interest represents the 30% interest in 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

We require cash to fund our operating expenses and working capital requirements, including outlays for the construction of new fueling stations, construction of LNG production facilities, the purchase of new LNG tanker trailers, investment in RNG 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 and regulatory initiatives and for working capital for our expansion. Our principal sources of liquidity are cash on hand, cash provided by operating activities and cash provided by financing activities.

Liquidity

Cash used in operating activities was $6.3 million for the six months ended June 30, 2012, compared to cash provided by operating activities of $9.9 million for the six months ended June 30, 2011. The decrease in operating cash flow resulted primarily from higher selling, general and administrative expenses and interest charges in the six month period ended June 30, 2012.

Cash used in investing activities was $63.1 million for the six months ended June 30, 2012, compared to $57.7 million for the six months ended June 30, 2011. We purchased property and equipment for $89.3 million in the six months ended June 30, 2012, which is an increase of $61.7 million from $27.6 million paid to purchase property and equipment in the six months ended June 30, 2011. This increase is primarily related to our initial efforts in building the first phase of American’s Natural Gas Highway that began in 2012. During the six months ended June 30, 2011, our restricted cash increased by $27.4 million, primarily related to the closing of the DCEMB bond offering. During the first six months of 2012, we used $31.2 million of our restricted cash balances for building out America’s Natural Gas Highway and funding the expansion at DCEMB’s landfill gas facility in Dallas, Texas. We made additional investments in The Vehicle Production Group, LLC (“VPG”), a company producing a CNG taxi and a paratransit vehicle, during the first six months of 2012 totaling $1.0 million, compared to $1.5 million during the first six months of 2011. We also invested $1.2 million in ServoTech Engineering, Inc. during the first six months of 2011. We purchased a net amount of $4.0 million of short-term investments during the first six months of 2012.

Table of Contents

Cash provided by financing activities for the six months ended June 30, 2012 was $3.0 million, compared to $28.9 million for the six months ended June 30, 2011. This decrease is primarily due to the 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. The decrease was offset by the increase of $7.1 million in net proceeds that we received from the exercise of employee stock options between periods. We also experienced a decrease of $9.4 million in repayment of capital lease obligations and debt instruments in the six months ended June 30, 2012. Additionally, the net borrowings under our revolving line of credit decreased by $4.0 million in the six months ended June 30, 2012.

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 contracts, 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, RNG plant construction costs and the purchase of LNG tanker trailers and equipment) and any merger or acquisition activity.

Sources of Cash

Historically, our principal sources of liquidity have consisted of cash provided by operations and financing activities. At June 30, 2012, we had total cash and cash equivalents of $172.7 million, compared to $238.1 million at December 31, 2011.

On July 11, 2011, we entered into a loan agreement with Chesapeake, an indirect wholly owned subsidiary of Chesapeake Energy Corporation, whereby Chesapeake agreed to purchase from us up to $150 million aggregate principal amount of debt securities for the development, construction and operation of LNG stations pursuant to the issuance of three convertible promissory notes, each having a principal amount of $50 million (collectively the “Notes”). Chesapeake Energy Corporation guaranteed Chesapeake’s commitment to purchase the Notes under the loan agreement. The first $50 million convertible promissory note was issued on July 11, 2011, the second note was issued on July 10, 2012, and the third note is expected to be issued in June 2013.

On August 30, 2011, we issued $150 million aggregate principal amount of debt securities to three institutional investors.

On December 27, 2011, we received aggregate net proceeds of $150 million from the exercise of warrants by Mr. Boone Pickens and certain third party investors.

Capital Expenditures

Our business plan calls for approximately $128.2 million in capital expenditures from July 1, 2012 through the end of 2012, primarily related to construction of new fueling stations, including stations along ANGH, expanding our California LNG plant, expansion and construction of landfill gas processing plants, and the purchase of LNG trailers. We may also elect to invest additional amounts in companies or assets in the natural gas fueling infrastructure, services and production industries, including RNG production. We will need to raise additional capital as necessary to fund any capital expenditures or investments that we cannot fund through available cash or cash generated by operations. The timing and necessity of any future capital raises will depend on our rate of new station construction and potential merger or acquisition activity. We may not be able to raise capital on terms that are favorable to existing stockholders or at all. Any inability to raise capital may impair our ability to invest in new stations, develop natural gas fueling infrastructure and invest in strategic transactions or acquisitions and may reduce the ability of our business to grow and generate increased revenues.

Off-Balance Sheet Arrangements

At June 30, 2012, we had the following off-balance sheet arrangements that had, or are reasonably likely to have, a material effect on our financial condition:

· outstanding surety bonds for construction contracts and general corporate purposes totaling $81.4 million,

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

· operating leases where we are the lessee,

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

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

Table of Contents

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 two contracts that require us to purchase minimum volumes of LNG at index based prices. One contract expires in June 2014 and the other contract expires in October 2017.

We have entered into operating lease arrangements for certain equipment and for our office and field operating locations in the ordinary course of business. The terms of our leases expire at various dates through 2018. 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 per year, plus up to $130 per year for each 30 million gallons of production capacity utilized, subject to future adjustment based on consumer price index changes. We must also pay a royalty to the landlord for each gallon of LNG produced at the facility, as well as a fee for certain other services that the landlord will provide.

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

Item 3.—Quantitative and Qualitative Disclosures about Market Risk

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

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

Natural gas costs represented 22% (or 32% excluding BAF, IMW and Northstar) of our cost of sales for 2011 and 19% (or 46% excluding BAF, IMW and Northstar) of our cost of sales for the six months ended June 30, 2012. Prices for natural gas over the twelve-year and six month period from December 31, 1999 through June 30, 2012, based on the NYMEX daily futures data, have ranged from a low of $1.65 per Mcf to a high of $19.38 per Mcf. At June 30, 2012, the NYMEX index price of natural gas was $2.42 per Mcf.

To reduce price risk caused by market fluctuations in natural gas, we may enter into exchange traded natural gas futures contracts. These arrangements also expose us to the risk of financial loss in situations where the other party to the contract defaults on

its contract or there is a change in the expected differential between the underlying price in the contract and the actual price of natural gas we pay at the delivery point.

We account for these futures contracts in accordance with FASB authoritative guidance on derivatives. The accounting under this guidance for changes in the fair value of a derivative depends upon whether it has been specified in a hedging relationship and, further, on the type of hedging relationship. To qualify for designation in a hedging relationship, specific criteria must be met and appropriate documentation maintained.

The fair value of the futures contracts we use is based on quoted prices in active exchange traded or over the counter markets, which are then discounted to reflect the time value of money for contracts applicable to future periods. The fair value of these futures contracts is continually subject to change due to market conditions. In an effort to mitigate the volatility in our earnings related to futures activities, our board of directors adopted a revised natural gas hedging policy which restricts our ability to purchase natural gas futures contracts and to offer fixed price sales contracts to our customers. We plan to structure prospective futures contracts so that they will be accounted for as cash flow hedges under the FASB guidance, but we cannot be certain they will qualify. For more information, please read “—Risk Management Activities” above.

We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to the futures contracts we hold as of June 30, 2012 to hedge the fixed price component of certain supply contracts. If the price of natural gas were to fluctuate (increase or decrease) by 10% from the price quoted on NYMEX on June 30, 2012 ($2.42 per Mcf), the corresponding fluctuation in the value of the contracts would not be material.

Table of Contents

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 $0.3 million of losses in the six months ended June 30, 2012. During the six months ended June 30, 2012, our primary exposure to foreign currency rates related to our Canadian operations that had certain outstanding notes payable denominated in the U.S. dollar which were not hedged.

We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to our monetary transactions denominated in a foreign currency. If the exchange rate on these assets and liabilities were to fluctuate by 10% from the rate as of June 30, 2012, we would expect a corresponding fluctuation in the value of the assets and liabilities of approximately $4.1 million.

Item 4.—Controls and Procedures

Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

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

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

PART II.—OTHER INFORMATION

Item 1.—Legal Proceedings

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

Item 1A.—Risk Factors

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

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

For the six month period ended June 30, 2012, we incurred pre-tax losses of $42.6 million, which included a derivative loss of $4.6 million related to marking to market the value of our Series I warrants. In 2009, 2010 and 2011, we incurred pre-tax losses of $33.4 million, $4.2 million, and $48.2 million, respectively. Our loss for 2009 includes $17.4 million of derivative losses related to marking to market the value of our Series I warrants; our loss for 2010 was decreased by a derivative gain of $10.3 million on our

Table of Contents

Series I warrants; and our loss for 2011 includes a $2.7 million derivative gain. During 2009, 2010 and 2011, our losses were substantially decreased by our receipt of approximately $15.5 million, $16.0 million, and $17.9 million of revenue from federal fuel tax credits, respectively. The program under which we received such credits expired on December 31, 2011. To build our business and improve our financial performance, we must continue to invest in developing the natural gas vehicle fuel market and offer our customers competitively priced natural gas vehicle fuel and other products and services. If we do not achieve or maintain profitability that can be sustained in the absence of federal fuel tax credits and other government incentive programs, 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 on December 31, 2011.

The federal excise tax credit of $0.50 per gasoline gallon equivalent of CNG and liquid gallon of LNG sold for vehicle fuel use, which began on October 1, 2006, expired December 31, 2011 and may not be reinstated. In 2009, 2010, and 2011 we recorded approximately $15.5 million, $16.0 million and $17.9 million of revenue, respectively, related to fuel tax credits, representing approximately 11.8%, 7.6% and 6.1%, respectively, of our total revenue during the periods. In addition, on July 15, 2010, the IRS sent us a letter disallowing approximately $5.1 million related to certain excise tax credit claims that we made from October 1, 2006 to June 30, 2008. We are appealing the IRS disallowance, and if we are unsuccessful, we may be required to refund some or all of the $5.1 million in contested claims.

The failure of our initiative to build America’s Natural Gas Highway would materially and adversely affect our financial results and business.

We are building America’s Natural Gas Highway (which we sometimes refer to as ANGH), a network of LNG truck fueling stations on interstate highways and in major metropolitan areas that we expect to initially consist of approximately 150 stations. Building America’s Natural Gas Highway requires a significant commitment of capital and other resources, and our ability to successfully execute our plan faces substantial risks, including:

· natural gas truck engines that are well-suited for the United States heavy-duty truck market may be adopted by fleet operators at a rate that is slower than our expectations due to, among other things, failure by manufacturers to develop and produce engines, performance issues relating to engines and the cost of engines;

· we may not be able to identify and obtain sufficient rights to use suitable locations for ANGH stations;

· development of America’s Natural Gas Highway will require substantial amounts of capital, which may not be available on terms favorable to us or at all;

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

· we will need to construct significantly more fueling stations in 2012 and 2013 than we have constructed in any fiscal year since we commenced operations, and we may not be able to hire and retain the necessary qualified personnel and our operational infrastructure and systems may be inadequate;

· we may be required to redirect resources from other areas of our business, including our refuse, transit, taxi and airport businesses;

· we may complete ANGH stations before there are sufficient numbers of customers who are capable of fueling at the stations, which would result in us having substantial investments in assets that do not produce revenues and may cause us to lose money on LNG fuel that is supplied to ANGH stations but is not purchased by customers;

· we may not be able to acquire and transport sufficient volumes of LNG to meet the needs of customers fueling at ANGH stations;

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

· building America’s Natural Gas Highway will impose significant added responsibilities on our management team and will divert their attention from other areas of our business.

Table of Contents

We must effectively manage these risks and any other risks that may arise in connection with the ANGH build-out to successfully execute our business plan. Failure to successfully execute our ANGH initiative will materially and adversely affect our financial results, operations and business.

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

We will be required to raise debt or equity capital to fund the growth of our business. At June 30, 2012, we had total cash and cash equivalents of $172.7 million and short-term investments of $37.1 million, and we received an additional $50.0 million in July 2012 pursuant to the terms of our Loan Agreement with Chesapeake NG Ventures Corporation. Our business plan calls for approximately $128.2 million in capital expenditures from July 1, 2012 through the end of 2012. 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 acquisitions of IMW and Northstar. At June 30, 2012, our future payments for IMW and Northstar totaled $32.5 million and $5.8 million, respectively. Our IMW future payment obligations are in the form of promissory notes, and such notes are secured by IMW’s assets. As a result, if we do not make scheduled IMW future payments, the party to whom such payments are due may be entitled to accelerate the maturity of the notes and exercise other remedies available to a secured creditor. We are also obligated to pay up to $40.0 million as additional consideration related to our IMW acquisition if IMW meets certain performance measurements.

Equity or debt financing options may not be available on terms favorable to us or at all. 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. Any debt financing we obtain may require us to make significant interest payments and to pledge some or all of our assets as security. If we are unable to obtain debt or equity financing in amounts sufficient to fund any unanticipated expenses, capital expenditures, mergers, acquisitions or strategic investments, we will be forced to suspend or curtail these capital expenditures or postpone or delay potential acquisitions or other strategic transactions, which would harm our business, results of operations, and future prospects.

We are required to make substantial future payments to the holders of our debt securities.

At June 30, 2012, we had an aggregate of $199.0 million of debt securities outstanding (such debt securities were issued in July and August 2011). In addition, we issued $50.0 million of debt securities in July 2012 and we have agreed to issue an additional $50.0 million of debt securities in June 2013. All such debt securities bear interest at the rate of 7.5% per annum. The $50.0 million principal amount of debt securities we issued in July 2011 is due and payable in July 2018; the $149.0 million principal amount of debt securities we issued in August 2011 is due and payable in August 2016; and the $50.0 million principal amount of debt securities we issued in July 2012 is due and payable in July 2019. We may repay the debt securities in common stock or cash. We expect our interest payment obligations under the debt securities to be approximately $16.9 million for the year ending December 31, 2012. In future periods, we may not have sufficient capital resources to enable us to fulfill our payment obligations to the holders of our debt securities. If we are unable to make scheduled payments or comply with the other provisions of the agreements relating to the debt securities, the holders of such debt securities may be permitted under certain circumstances to accelerate the maturity of the debt securities and exercise other remedies provided for in the securities and under applicable law. An acceleration of the maturity of the debt securities that is not rescinded would have a material adverse effect on our company.

Our growth is influenced by government incentives and mandates for clean burning fuels and alternative fuel vehicles. The failure to pass new legislation with new incentive programs may adversely affect our business.

Our business is influenced by federal, state and local government tax credits, rebates, grants and similar incentives that promote the use of natural gas as a vehicle fuel, as well as by laws, rules and regulations that require reductions in carbon emissions. Some government programs and incentives have recently expired, such as the federal income tax credit that was available to offset 50% to 80% of the incremental cost of purchasing new or converted natural gas vehicles, and the absence of these programs and incentives could have a detrimental effect on the natural gas vehicle and fueling industry, including sales at our wholly owned subsidiary, BAF. If expired incentives are not reinstated or extended, or if new incentives are not passed, fewer natural gas vehicles may be sold and used and our revenue and financial performance may be adversely affected. Furthermore, the failure of proposed federal, state or local government incentives, such as the so-called federal “NAT GAS Act,” 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. Changes to or the repeal of laws, rules and regulations that mandate reductions in carbon emissions and/or the use of renewable fuels, including the California Low Carbon Fuel Standard and the Federal Renewable Fuel Standard Phase II, would adversely affect our business. In addition, if grant funds are no longer available under 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 may be adversely affected. Continued reduction in tax revenues associated with high unemployment rates, economic recession or slow-down could result in a significant reduction in funds available for government grants that support vehicle conversion and station construction, which could impair our ability to grow our business.

Table of Contents

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

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

We depend on key personnel to operate our business, and if we are unable to retain our current personnel or hire additional personnel, our ability to develop and successfully market our business would be harmed.

We believe that our future success is highly dependent on the contributions of our executive officers, as well as our ability to attract and retain highly skilled managerial, sales, technical and finance personnel. Qualified individuals are in high demand, and we may incur significant costs to attract and retain them. All of our executive officers and other United States employees may terminate their employment relationship with us at any time, and their knowledge of our business and industry would be extremely difficult to replace. If we are unable to attract and retain our executive officers and key employees, our business, operating results and financial condition will be harmed. In addition, our management team has a long history of working together, and we believe that our key executives have developed highly successful and effective working relationships. If one or more of these individuals leave, we may not be able to fully integrate new executives or replicate the current dynamic, which may cause our operations to suffer.

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

Limited availability of natural gas vehicles and engine sizes restricts their wide scale introduction and narrows our potential customer base. Original equipment manufacturers produce a small number of natural gas engines and vehicles in the U.S. and Canadian markets, and they may not make adequate investments to expand their natural gas engine and vehicle product lines. The technology used 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. Natural gas 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 heavy duty LNG truck purchasers are not satisfied with truck performance, additional heavy-duty truck engine manufacturers do not enter the market for LNG engines, or LNG engines are not otherwise developed, produced and adopted in greater numbers, our ANGH investments and LNG fueling business may be significantly impaired, which would adversely affect our financial performance. Due to the limited supply of natural gas vehicles, our ability to promote natural gas vehicles and our natural gas fuel sales will be restricted.

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

Natural gas vehicles cost more than comparable gasoline or diesel powered vehicles because the components needed for a vehicle to use natural gas adds to a vehicle’s base cost. If the prices of CNG and LNG do not remain sufficiently below the prices of gasoline or diesel, 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, gasoline and diesel declines, it will make it more difficult for us to offer our customers discounted prices for CNG and LNG as compared to gasoline and diesel prices and maintain an acceptable margin on our sales. Recent and significant volatility in oil and gasoline prices demonstrate that it is difficult to predict future transportation fuel costs. In addition, any new regulations imposed on natural gas extraction in the United States, particularly on extraction of natural gas from shale formations, could increase the costs of domestic gas production or make it more costly to produce natural gas in the United States, which could lead to substantial increases in the price of natural gas. Reduced prices for gasoline and diesel fuel, combined with higher costs for natural gas and natural gas vehicles, may cause potential customers to delay or reject converting their fleets to run on natural gas. In that event, our sales of natural gas fuel and vehicles would be slowed and our business would suffer.

Table of Contents

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 June 30, 2012, the price for natural gas, based on the NYMEX daily futures data, ranged from a low of $1.65 per Mcf to a high of $19.38 per Mcf. At June 30, 2012, the NYMEX index price for natural gas was $2.42 per Mcf. Increased natural gas prices affect the cost to us of natural gas and will adversely impact our operating margins in cases where we have committed to sell natural gas at a fixed price without an effective futures contract in place that fully mitigates the price risk or where we otherwise cannot pass the increased costs on to our customers. In addition, higher natural gas prices may cause CNG and LNG to cost as much as or more than gasoline and diesel generally, which would adversely impact the adoption of CNG and LNG as a vehicle fuel and consequently our business. Conversely, lower natural gas prices reduce our revenues due to the fact that in a significant number of our customer agreements, the commodity cost is passed through to the customer. Among the factors that can cause 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 efforts to place new regulatory requirements on the production of natural gas by hydraulic fracturing of shale gas reservoirs. Hydraulic fracturing of shale gas reservoirs has resulted in a substantial increase in the proven natural gas reserves in the United States, and any changes in regulations that make it more expensive or unprofitable to produce natural gas through hydraulic fracturing could lead to increased natural gas prices.

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

Our business depends in part on environmental regulations and programs in the United States that promote or mandate the use of cleaner burning fuels, including natural gas for vehicles. Industry participants with a vested interest in gasoline and diesel, many of which have substantially greater resources than we do, invest significant time and money in an effort to influence environmental regulations in ways that delay or repeal requirements for cleaner vehicle emissions. Further, economic difficulties may result in the delay, amendment or waiver of environmental regulations due to the perception that they impose increased costs on the transportation industry that cannot be absorbed in a challenging economy. Further, the delay, repeal or modification of federal or state regulations or programs that encourage the use of cleaner vehicles could also have a detrimental effect on the United States natural gas vehicle industry, which, in turn, could slow our growth and adversely affect our business.

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

To expand our business, we must develop new customers and obtain and fulfill CNG and LNG fueling contracts from these customers. We may not be able to develop these customers or obtain these fueling contracts. Whether we will be able to expand our customer base will depend on a number of factors, including the level of acceptance and availability of natural gas vehicles, the growth in our target markets of fueling station infrastructure that supports CNG and LNG sales, our ability to supply CNG and LNG at competitive prices and acceptance of our technology, fuel systems and services. A decline in oil, diesel fuel and gasoline prices may result in decreased interest in alternative fuels like CNG and LNG. Further, potential customers may not find our technology, fuel systems or services acceptable.

We face increasing competition from oil and gas companies, retail fuel providers, refuse companies, industrial gas companies, natural gas utilities, and other organizations that have far greater resources and brand awareness than we have.

A significant number of established businesses, including oil and gas companies, refuse collectors, natural gas utilities, industrial gas companies, station owners and other organizations have entered or are planning to enter the natural gas fuels market. For example, Shell Oil Products U.S. recently announced its plans to construct and operate a network of natural gas fueling stations at TravelCenters of America locations in the U.S. Many of these current and potential competitors have substantially greater financial, marketing, research and other resources than we have. Natural gas utilities, particularly in California, continue to own and operate natural gas fueling stations that compete with our stations. Utilities in Michigan, Illinois, New Jersey, North Carolina and Georgia have also recently made efforts to invest in the natural gas vehicle fuel space. We expect competition to intensify in the near term in the market for natural gas vehicle fuel as the use of natural gas vehicles and the demand for natural gas vehicle fuel increases. Increased competition will lead to amplified pricing pressure, reduced operating margins and fewer expansion opportunities. To compete effectively in this environment, we must continually develop and market new and enhanced product offerings at competitive prices and must have the resources available to invest in the further development of our business. Our failure to compete successfully would adversely affect our business and financial results.

Table of Contents

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. 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. 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, including:

· compliance with the United States Foreign Corrupt Practices Act;

· political unrest, terrorism and economic and financial instability;

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

· import-export regulations;

· difficulties in enforcing agreements and collecting receivables;

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

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

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

· limited intellectual property protection;

· 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 United States dollars or move funds from accounts in these countries. We are also vulnerable to appreciation or depreciation of foreign currencies against the United States dollar. We do not engage in currency hedging activities to limit the risks of currency fluctuations.

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

The integration of IMW into our business presents significant challenges and risks to our business, including (i) the distraction of management from other business concerns, (ii) the retention of customers of IMW, (iii) expansion into foreign markets, (iv) the introduction of IMW’s compressor and related equipment manufacturing and servicing business, which is a new product line for us, (v) achievement of appropriate internal controls over financial reporting and (vi) the monitoring of compliance with all laws and regulations. IMW derives significant revenue from sales in emerging markets, and prior to the acquisition, IMW was not required to comply with the United States Foreign Corruption Practices Act or any of the requirements of Sarbanes-Oxley. If we do not successfully integrate IMW into our business and maintain regulatory compliance, we may not realize the benefits expected from the acquisition and our results of operations could be materially adversely affected. If the revenue of IMW declines or grows more slowly than we anticipate, or if its operating expenses are higher than we expect, we may not be able to achieve, sustain or increase the growth of our business, in which case our financial condition will suffer and our stock price could decline.

Table of Contents

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 initially 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.

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

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

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

Gasoline and diesel fueling stations and service infrastructure are widely available in the United States. For natural gas vehicle fuels to achieve more widespread use in the United States and Canada, they will require a promotional and educational effort and the development and supply of more natural gas vehicles and fueling stations. This will require significant continued effort by us, as well as government and clean air groups, and we may face resistance from oil companies and other vehicle fuel companies.

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

We have existing, and will continue to seek, long-term CNG and LNG station construction, maintenance and fuel sales contracts with various federal, state and local governmental bodies, which accounted for approximately 26% of our revenues for the six month period ended June 30, 2012 and approximately 59%, 42% and 33% of our annual revenues in 2009, 2010 and 2011, respectively. 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.

Further, government contracts are frequently awarded only after competitive bidding processes, which have been and may continue to be protracted. In many cases, unsuccessful bidders for government agency contracts are provided the opportunity to formally protest certain contract awards through various agency, administrative and judicial channels. The protest process may substantially delay a successful bidder’s contract performance, result in cancellation of the contract award entirely and distract management. We may not be awarded contracts for which we bid, and substantial delays or cancellation of purchases may even follow our successful bids as a result of such protests.

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

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

Table of Contents

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

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

A majority of BAF’s sales of CNG vehicles in recent years has been to one customer. If this customer does not continue to purchase CNG vehicles, and BAF is unable to sell CNG vehicles to other customers, BAF’s revenue will decline.

During 2009 and 2010, BAF derived approximately 63% and 66%, respectively, of its revenue from AT&T. In 2011, and through June 30, 2012, AT&T significantly reduced its purchases from BAF, resulting in a substantial decline in BAF’s revenue. If AT&T does not increase its purchases, in the absence of additional sales to other customers, BAF will experience materially reduced revenues and may require additional cash to continue its operations, which could adversely affect our capital resources and financial results.

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. Use of electric heavy duty trucks or the perception that electric heavy duty trucks may soon be widely available and provide satisfactory performance in heavy duty applications may reduce demand for heavy duty LNG trucks. In addition, hydrogen and other alternative fuels in experimental or developmental stages may eventually offer a cleaner, more cost-effective alternative to gasoline and diesel than natural gas. Advances in technology that slow the growth of or conversion to natural gas vehicles, or which otherwise reduce demand for natural gas as a vehicle fuel, will have an adverse effect on our business. Failure of natural gas vehicle technology to advance at a sufficient pace may also limit its adoption and our ability to compete with other alternative fuels and alternative fuel vehicles.

Our ability to obtain LNG is constrained by fragmented and limited production and increasing competition for the LNG supply.

Production of LNG in the United States is fragmented and limited. It may be difficult for us to obtain LNG without interruption and near our current or target markets at competitive prices or at all. If LNG liquefaction plants we own, or if any of those from which we purchase LNG, are damaged by severe weather, earthquake or other natural disaster, or otherwise experience prolonged down time, or if new LNG liquefaction plants are not built, our LNG supply will be restricted. 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 customer demand, we may be liable to our customers for penalties. Further, competition for LNG supply is increasing. In addition, the execution of our business plan will require substantial growth in the available LNG supply across the United States, and if this supply is unavailable, it will constrain our ability to increase the market for LNG fuel, including supplying LNG fuel to heavy duty truck customers, and will adversely affect our investments in America’s Natural Gas Highway. If we experience an LNG supply interruption or LNG demand that exceeds available supply, or if we have difficulty entering or maintaining relationships with contract carriers to deliver LNG on our behalf, our ability to expand LNG sales to new customers will be limited, our relationships with existing customers may be disrupted, and our results of operations may be adversely affected. Furthermore, because transportation of LNG is relatively expensive, if we are required to supply LNG 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.

Table of Contents

LNG supply purchase commitments may exceed demand causing our costs to increase.

We are a party to two LNG supply agreements that have a take-or-pay commitment, and we may enter into additional take-or-pay commitments, particularly in connection with our development of ANGH. 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. Should the market demand for LNG decline, if we lose significant LNG customers, if demand under any existing or any future LNG supply contract does not maintain its volume levels or grow, or if future demand for LNG does not meet our expectations, our operating and supply costs may increase as a percentage of revenue and negatively impact our margins.

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

Some regions of the United States and Canada depend heavily on natural gas supplies coming from particular fields or pipelines. Interruptions in field production or in pipeline capacity could reduce the availability of natural gas or possibly create a supply imbalance that increases natural gas prices. We have in the past experienced LNG supply disruptions due to severe weather in the Gulf of Mexico and plant outages. If there are interruptions in field production, insufficient pipeline capacity, failure of liquefaction production equipment or delivery delays, we may experience supply stoppages that 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.

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

We account for our futures activities under the relevant derivative accounting guidance, which requires us to value our futures contracts at fair market value in our financial statements. Prior to June 2008, our futures contracts did not qualify for hedge accounting, and therefore we have recorded any changes in the fair market value of these contracts directly in our consolidated statements of operations in the line item “derivative (gains) losses” along with any realized gains or losses during the period. At June 30, 2012, 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, 2011 and for the six months ended June 30, 2012. Any negative fluctuations may cause our stock price to decline due to our failure to meet or exceed the expectations of securities analysts or investors.

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

California has adopted legislation, AB 32, which calls for a cap on greenhouse gas emissions throughout California and a statewide reduction to 1990 levels by 2020 and an additional 80% reduction below 1990 levels by 2050. Other states and the federal government are considering passing measures to regulate and reduce greenhouse gas emissions. Any of these regulations, when and if implemented, may regulate the greenhouse gas emissions produced by our LNG production plants in California and Texas or our CNG and LNG fueling stations and require that we obtain emissions credits or invest in costly emissions prevention technology. We cannot currently estimate the potential costs associated with federal or state regulation of greenhouse gas emissions from our LNG plants or CNG and LNG stations, and these unknown costs are not contemplated by 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 or installed, may rupture and the contents of the tank may rapidly decompress and result in death or injury. These risks may expose us to liability for personal injury, wrongful death, property damage, pollution and other environmental damage. We may incur substantial liability and cost if damages are not covered by insurance or are in excess of policy limits. 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.

Table of Contents

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. These risks include the following: (i) the equipment financed consists mostly of vehicles that are mobile and easily damaged, lost or stolen, (ii) there is a risk the borrower may default on payments, (iii) we may not be able to bill properly or track payments in adequate fashion to sustain growth of this service, and (iv) the amount of capital available to us is limited and may not allow us to make loans required by customers. Some of our customers, such as taxi owners, may depend on the CNG vehicles that we finance or lease to them as their sole source of income, which may make it difficult for us to recover the collateral in a bankruptcy proceeding. As of June 30, 2012, we had $7.5 million outstanding in loans provided to customers to finance natural gas vehicle purchases.

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 foreign business practices, the environment, health and safety, labor and employment and taxation, among others. These laws and regulations are complex, change frequently and have tended to become more stringent over time. Failure to comply with these laws and regulations may result in a variety of administrative, civil and criminal enforcement measures, including assessment of monetary penalties and the imposition of remedial requirements. From time to time, as part of the regular overall evaluation of our operations, including newly acquired operations, we may be subject to compliance audits by regulatory authorities. In addition, any failure to comply with regulations related to the government procurement process at the federal, state or local level or restrictions on political activities and lobbying may result in administrative or financial penalties including being barred from providing services to governmental entities.

In connection with our LNG liquefaction and landfill gas processing operations, 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 RNG business.

We are developing pipeline quality RNG projects outside of Detroit, Michigan and Memphis, Tennessee. We are also in the process of expanding operations at our RNG production facility at the McCommas Bluff landfill outside of Dallas, Texas. In addition, we are seeking to increase our RNG business by pursuing additional projects. RNG 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 RNG have often failed due to the volatile prices of conventional natural gas, unpredictable RNG production levels, technological difficulties and costs associated with operating the production facilities, and the absence of government programs and regulations that support such activities. Our ability to succeed in expanding our McCommas Bluff project and developing other projects in the future depends on our ability to obtain necessary financing, successfully manage the construction and operation of RNG production facilities, and our ability to either sell the RNG at substantial premiums to recent conventional natural gas prices or to sell, at favorable prices, credits we may generate under federal or state laws, rules and regulations, including “RINs” that may be generated under the Federal Renewable Fuel Standard Phase II by selling the RNG in the vehicle fuels market. If we are unsuccessful in obtaining necessary financing or managing the construction and operation of our RNG production facilities, or if we are unable to either sell RNG at a substantial premium to conventional natural gas prices or to sell RINs or other credits we generate at favorable prices, our business and financial results may be materially and adversely affected. In addition, the California Energy Commission has suspended the renewable portfolio standard (“RPS”) eligibility for certifying power plants that generate electricity from RNG produced outside the state of California. Unless lifted or modified, this suspension will limit our ability to sell RNG produced by our projects to California utilities. If we cannot sell RNG we produce to California utilities for use as an RPS compliant fuel, we may not be able to obtain premium prices for RNG. In the absence of state and federal programs that support premium prices for RNG or that allow us to generate and sell RINs or other credits , we will be unable to generate profit and financial return from these investments, and our financial results could be materially and adversely affected.

Table of Contents

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

In August 2008, we acquired our 70% interest in DCE, which owns 100% of DCEMB. DCEMB is a party to a 15-year gas sale agreement with Shell for the sale to Shell of specified levels of RNG produced by DCEMB’s landfill gas processing facility. DCEMB may not be able to produce or sell up to the maximum volumes called for under the agreement or produce RNG that meets the relevant pipeline specification. DCEMB’s ability to produce such volumes of RNG depends on a number of factors beyond DCEMB’s control, including, but not limited to, the availability and composition of the landfill gas that is collected, successful permitting, the operation of the landfill by the City of Dallas, the reliability of the processing facility’s critical equipment and weather conditions. The DCEMB facility is subject to periods of reduced production or non-production due to upgrades, maintenance, repairs and other factors. Severe winter weather in Texas resulted in power outages and broken equipment in February 2011, resulting in a week of down time and an extended period during which the plant operated at half capacity. In addition, production was negatively affected by the recent severe drought and high temperature conditions in Texas. Also, we are expanding DCEMB’s facility, and such expansion may require a plant shutdown, may not be completed on time, and may cost more than we expect. The occurrence of one or more of the foregoing could adversely affect DCEMB’s financial results. Future operational upgrades, including planned expansion of the plant, or other complications in the operations of the facility could require shutdowns, and accordingly, DCEMB’s revenues may fluctuate from quarter to quarter.

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

Our quarterly results of operations have historically experienced significant fluctuations. Our net losses (income) were approximately $6.5 million, $6.4 million, $18.5 million, $1.9 million, $24.4 million, $(9.9) million, $1.8 million, $(13.8) million, $9.8 million, $5.6 million, $11.4 million, $(20.9) million, $31.9 million, and $11.3 million for the three months ended March 31, 2009, June 30, 2009, September 30, 2009, December 31, 2009, March 31, 2010, June 30, 2010, September 30, 2010, December 31, 2010, March 31, 2011, June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, and June 30, 2012, 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, down time at our facilities (including any shutdowns of DCEMB’s landfill gas processing facility), the amount and timing of operating costs, unanticipated expenses, capital expenditures related to the maintenance and expansion of our business, operations and infrastructure, our debt service obligations, changes in the price of natural gas, changes in the prices of CNG and LNG relative to gasoline and diesel, changes in our pricing policies or those of our competitors, fluctuation in the value of our natural gas futures contracts, the costs related to the acquisition of assets or businesses, regulatory changes, and geopolitical events such as war, threat of war or terrorist actions. Investors in our stock should not rely on the results of one quarter as an indication of future performance as our quarterly revenues and results of operations may vary significantly in the future. Therefore, period-to-period comparisons of our operating results may not be meaningful.

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

As of June 30, 2012, there were 86,790,309 shares of our common stock outstanding, 10,564,834 shares underlying outstanding options, 1,545,000 shares underlying restricted stock units, 2,130,682 shares underlying outstanding warrants (all of which were sold in our registered direct offering that closed in November 2008) and 13,097,669 shares underlying the convertible notes we issued in July and August 2011. All of our outstanding shares are eligible for sale in the public market, subject in certain cases to the requirements of Rule 144 of the Securities Act. Also, shares subject to outstanding options, warrants and convertible notes are eligible for sale in the public market to the extent permitted by the provisions of various option, warrant and convertible note agreements and Rule 144, or if such shares have been registered for resale under the Securities Act (8,999,999 shares underlying convertible notes we issued in August 2011 have been registered for resale under the Securities Act). If these shares are sold, or if it is perceived that they will be sold in the public market, the trading price of our common stock could decline.

Further, as of June 30, 2012, 16,539,720 shares of our common 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 June 30, 2012, 586,418 shares in the aggregate were subject to future sales by our named executive officers and directors under these selling plans. All sales of common stock under the plans will be reported through appropriate filings with the SEC.

Table of Contents

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

As of June 30, 2012, T. Boone Pickens and affiliates (including Madeleine Pickens, his wife) owned in the aggregate approximately 21.0% of our outstanding shares of common stock. 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 that 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.

Table of Contents

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

None.

Item 3.—Defaults upon Senior Securities

None.

Item 4.— Mine Safety Disclosures

None.

Item 5.—Other Information

None.

Item 6.—Exhibits

(a) Exhibits

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

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

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

101†		The following materials from the Company’s Quarterly Report of Form 10-Q for the quarter ended June 30, 2012, formatted in XBRL (eXtensible Business Reporting Language):

		(i) Condensed Consolidated Balance Sheets at December 31, 2011 and June 30, 2012;
		(ii) Condensed Consolidated Statements of Operations for the Three Months and Six Months Ended June 30, 2011 and 2012;
		(iii) Condensed Consolidated Statements of Comprehensive Income for the Three Months and Six Months Ended June 30, 2011 and 2012;
		(iv) Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2011 and 2012; and
		(v) Notes to Condensed Consolidated Financial Statements, tagged as block of text.

Filed herewith.

†

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

Table of Contents

SIGNATURE

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

	CLEAN ENERGY FUELS CORP.


Date: August 6, 2012	By:	/s/ RICHARD R. WHEELER
		Richard R. Wheeler
		Chief Financial Officer (Principal financial officer and duly authorized to sign on behalf of the registrant)