Clean Energy Fuels Corp. - Quarter Report: 2013 March (Form 10-Q)

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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 March 31, 2013

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. Yes x No o

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 x		Accelerated filer o

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 May 1, 2013, there were 88,514,691 shares of the registrant’s common stock, par value $0.0001 per share, issued and outstanding.

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

INDEX

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PART I.—FINANCIAL INFORMATION
Item 1.—Financial Statements (Unaudited)	3
Item 2.—Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3.—Quantitative and Qualitative Disclosures about Market Risk	30
Item 4.—Controls and Procedures	31
PART II.—OTHER INFORMATION
Item 1.—Legal Proceedings	31
Item 1A.—Risk Factors	32
Item 2.—Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 3.—Defaults upon Senior Securities	42
Item 4.—Mine Safety Disclosures	42
Item 5.—Other Information	43
Item 6.—Exhibits	44

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PART I.—FINANCIAL INFORMATION

Item 1.—Financial Statements (Unaudited)

Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Balance Sheets

December 31, 2012 and March 31, 2013

(Unaudited)

(In thousands, except share data)

	December 31, 2012			March 31, 2013
Assets
Current assets:
Cash and cash equivalents	$	108,522		$	82,572
Restricted cash	8,445			9,507
Short-term investments	38,175			37,966
Accounts receivable, net of allowance for doubtful accounts of $905 and $818 as of December 31, 2012 and March 31, 2013, respectively	57,594			47,359
Other receivables	17,808			45,425
Inventory, net	38,152			44,218
Prepaid expenses and other current assets	16,002			17,870
Total current assets	284,698			284,917
Land, property and equipment, net	428,177			438,408
Restricted cash	13,208			1,435
Notes receivable and other long-term assets	71,389			69,951
Investments in other entities	2,581			—
Goodwill	75,865			74,884
Intangible assets, net	99,282			95,275
Total assets	$	975,200		$	964,870
Liabilities and Stockholders’ Equity
Current liabilities:
Current portion of long-term debt and capital lease obligations	$	30,389		$	28,851
Accounts payable	39,216			21,988
Accrued liabilities	30,794			41,188
Deferred revenue	13,521			13,907
Total current liabilities	113,920			105,934
Long-term debt and capital lease obligations, less current portion	300,636			286,091
Other long-term liabilities	14,014			14,534
Total liabilities	428,570			406,559
Commitments and contingencies
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 87,634,478 shares and 88,511,691 shares at December 31, 2012 and March 31, 2013, respectively	9			9
Additional paid-in capital	837,367			855,287
Accumulated deficit	(300,814		)	(304,685		)
Accumulated other comprehensive income	6,151			3,747
Total Clean Energy Fuels Corp. stockholders’ equity	542,713			554,358
Noncontrolling interest in subsidiary	3,917			3,953
Total stockholders’ equity	546,630			558,311
Total liabilities and stockholders’ equity	$	975,200		$	964,870

See accompanying notes to condensed consolidated financial statements.

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Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Statements of Operations

For the Three Months Ended March 31, 2012 and 2013

(Unaudited)

(In thousands, except share and per share data)

	Three Months Ended March 31,
	2012			2013
Revenue:
Product revenues	$	65,776		$	83,483
Service revenues	7,858			9,560
Total revenues	73,634			93,043
Operating expenses:
Cost of sales:
Product cost of sales	51,902			46,814
Service cost of sales	3,984			3,927
Derivative losses:
Series I warrant valuation	13,506			466
Selling, general and administrative	24,850			32,876
Depreciation and amortization	8,144			10,158
Total operating expenses	102,386			94,241
Operating loss	(28,752		)	(1,198		)
Interest expense, net	(3,702		)	(5,071		)
Other income (expense), net	841			(390		)
Income (loss) from equity method investment	91			(76		)
Gain from sale of equity method investment	—			4,705
Loss before income taxes	(31,522		)	(2,030		)
Income tax expense	(246		)	(1,805		)
Net loss	(31,768		)	(3,835		)
Income of noncontrolling interest	(137		)	(36		)
Net loss attributable to Clean Energy Fuels Corp.	$	(31,905	)	$	(3,871	)
Loss per share attributable to Clean Energy Fuels Corp.:
Basic	$	(0.37	)	$	(0.04	)
Diluted	$	(0.37	)	$	(0.04	)
Weighted-average common shares outstanding:
Basic	85,677,090			93,132,454
Diluted	85,677,090			93,132,454

See accompanying notes to condensed consolidated financial statements.

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Clean Energy Fuels Corp. and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Loss)

For the Three Months Ended March 31, 2012 and 2013

(Unaudited)

(In thousands)

	Clean Energy Fuels Corp.						Noncontrolling Interest				Total
	Three Months Ended March 31,						Three Months Ended March 31,				Three Months Ended March 31,
	2012			2013			2012		2013		2012			2013
Net income (loss)	$	(31,905	)	$	(3,871	)	$	137	$	36	$	(31,768	)	$	(3,835	)

Other comprehensive income, net of tax:
Foreign currency translation adjustments	(1,475		)	(655		)	—		—		(1,475		)	(655		)
Foreign currency adjustments on intra-entity long-term investments	1,142			(1,818		)					1,142			(1,818		)
Unrealized losses on available-for-sale securities	(116		)	(37		)	—		—		(116		)	(37		)
Unrecognized gains on derivatives	715			106			—		—		715			106
Total other comprehensive income, net of tax	266			(2,404		)	—		—		266			(2,404		)

Comprehensive income (loss)	$	(31,639	)	$	(6,275	)	$	137	$	36	$	(31,502	)	$	(6,239	)

See accompanying notes to condensed consolidated financial statements.

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Clean Energy Fuels Corp.

Condensed Consolidated Statements of Cash Flows

For the Three Months Ended March 31, 2012 and 2013

(Unaudited)

(In thousands)

	Three Months Ended March 31,
	2012			2013
Cash flows from operating activities:
Net loss	$	(31,768	)	$	(3,835	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization	8,144			10,158
Provision for doubtful accounts, notes and inventory	209			17
Loss on disposal of assets	—			137
Derivative loss	13,506			466
Stock-based compensation expense	4,680			6,212
Amortization of debt issuance cost	113			262
Accretion of notes payable	555			340
Gain on sale of equity method investment	—			(4,705		)
Dividend received on equity method investment	—			1,091
Gain on contingent consideration for acquisition	(2,648		)	—
Changes in operating assets and liabilities, net of assets and liabilities acquired:
Accounts and other receivables	(1,729		)	(17,961		)
Inventory	(3,369		)	(6,066		)
Prepaid expenses and other assets	(7,891		)	(2,276		)
Accounts payable	(8,654		)	(11,742		)
Accrued expenses and other	11,956			10,970
Net cash used in operating activities	(16,896		)	(16,932		)
Cash flows from investing activities:
Purchases of short-term investments	(4,564		)	(21,227		)
Maturities of short-term investments	—			21,233
Purchases of property and equipment	(36,623		)	(21,703		)
Proceeds from sale of property and equipment	—			95
Loans made to customers	(3,057		)	(361		)
Payments on and proceeds from sales of loans receivable	2,568			2,271
Restricted cash	9,634			10,711
Proceeds from sale of equity method investment	—			6,119
Net cash used in investing activities	(32,042		)	(2,862		)
Cash flows from financing activities:
Proceeds from issuance of common stock and exercise of stock options	5,947			178
Proceeds from debt instruments	76			—
Proceeds from revolving line of credit	15,069			6,894
Repayment of borrowing under revolving line of credit	(15,002		)	(7,380		)
Repayment of capital lease obligations and debt instruments	(5,547		)	(5,601		)
Net cash provided by (used in) financing activities	543			(5,909		)
Effect of exchange rates on cash and cash equivalents	936			(247		)
Net decrease in cash	(47,459		)	(25,950		)
Cash, beginning of period	238,125			108,522
Cash, end of period	$	190,666		$	82,572
Supplemental disclosure of cash flow information:
Income taxes paid	$	559		$	1,653
Interest paid, net of approximately $1,517 and $829 capitalized, respectively	2,359			4,014

See accompanying notes to condensed consolidated financial statements.

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Clean Energy Fuels Corp. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(In thousands, except share and per 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 and Canada.

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 358 natural gas fueling locations in thirty-two 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, through manufacturing and servicing natural gas fueling compressors and related equipment, providing natural gas vehicle conversions, providing design and engineering services for natural gas engine systems, processing and selling renewable natural gas (“RNG”), and through financing its customers’ vehicle purchases and selling tradable credits the Company generates by selling natural gas and RNG as a vehicle fuel, including credits (“LCFS Credits”) under the California low carbon fuel standard and Renewable Identification Numbers (“RIN Credits”) under the federal Renewable Fuel Standard Phase 2.

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 months ended March 31, 2012 and 2013. All intercompany accounts and transactions have been eliminated in consolidation. The three month periods ended March 31, 2012 and 2013 are not necessarily indicative of the results to be expected for the year ending December 31, 2013 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, 2012 that are included in the Company’s Annual Report on Form 10-K filed with the SEC on February 28, 2013.

Use of Estimates: The preparation of condensed 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 condensed consolidated financial statements and revenues and expenses recorded during the reporting period. Actual results could differ from those estimates.

Note 2—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 3—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 December 31, 2012 and March 31, 2013:

	December 31, 2012		March 31, 2013
Short-term restricted cash
Standby letters of credit	$	669	$	669
DCEMB bonds — current operating costs	7,776		8,838
Total short-term restricted cash	8,445		9,507
Chesapeake Notes	12,256		483
DCEMB bonds — long-term plant expansion	952		952
Total restricted cash	$	21,653	$	10,942

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Note 4—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 March 31, 2013, the Company believes its cost bases for its available-for-sale investments are properly recorded.

Short-term investments as of December 31, 2012 are summarized as follows:

	Amortized Cost		Gross Unrealized Losses			Estimated Fair Value
Municipal bonds & notes	$	23,755	$	(105	)	$	23,650
Corporate bonds	4,557		(53		)	4,504
Total available-for-sale securities	28,312		(158		)	28,154
Certificate of deposits	10,021		—			10,021
Total short-term investments	$	38,333	$	(158	)	$	38,175

Short-term investments as of March 31, 2013 are summarized as follows:

	Amortized Cost		Gross Unrealized Losses		Estimated Fair Value
Municipal bonds & notes	$	23,698	(158	)	$	23,540
Zero coupon bonds	124		—		124
Corporate bonds	4,277		(37	)	4,240
Total available-for-sale securities	28,099		(195	)	27,904
Certificate of deposits	10,062		—		10,062
Total short-term investments	$	38,161	(195	)	$	37,966

Note 5—Derivative Transactions

The Company, in an effort to manage its natural gas commodity price risk exposures related to certain contracts, utilizes derivative financial instruments. From time to time, the Company enters into natural gas future contracts that are over-the-counter swap transactions that convert its index-based gas supply arrangements to fixed price arrangements. As of March 31, 2013, all of the Company’s future contracts are being accounted for as cash flow hedges and are being used to mitigate the Company’s exposure to changes in the price of natural gas and not for speculative purposes. 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 March 31, 2012 and 2013, the Company recorded unrealized gains of $715 and $106, respectively, in other comprehensive income (loss) related to its futures contracts. Of the Company’s net futures contracts liability of $2 at March 31, 2013, $36 was recorded as a liability in accrued liabilities and $34 was recorded as an asset in prepaid expenses and other current assets, which are included in the Company’s condensed consolidated balance sheet. Of the Company’s net futures contracts liability of $107 at December 31, 2012, $5 was recorded as an asset in prepaid expenses and other current assets and $112 was recorded as an accrued liability in the Company’s condensed consolidated balance sheet. The Company’s ineffectiveness related to its futures contracts during the three month periods ended March 31, 2012 and 2013 was insignificant. For the three months ended March 31, 2012 and 2013, the Company recognized a loss of approximately $1,107 and $22, respectively, in cost of sales in the accompanying condensed consolidated statement of operations related to its futures contracts that were settled during the respective periods. As of March 31, 2013, the remaining unrecognized loss of $2 is recorded as a component of accumulated other comprehensive income (loss). The Company expects to reclassify such unrecognized loss from accumulated other comprehensive income (loss) as cost of sales through June 30, 2013.

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The following table presents the notional amount and weighted-average fixed price per gasoline gallon equivalent of the Company’s natural gas futures contracts as of March 31, 2013:

	Gallons	Weighted Average Price Per Gasoline Gallon Equivalent
April to June, 2013	540,000	$	0.51

Note 6—Other Receivables

Other receivables at December 31, 2012 and March 31, 2013 consisted of the following:

	December 31, 2012		March 31, 2013
Loans to customers to finance vehicle purchases	$	4,151	$	3,646
Capital lease receivables	308		311
Accrued customer billings	6,934		6,088
Fuel tax and carbon credits	2,780		32,867
Other	3,635		2,513
	$	17,808	$	45,425

Note 7—Inventories

Inventories are stated at the lower of cost or market value on a first-in, first-out basis. Management’s estimate of market value 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, 2012 and March 31, 2013:

	December 31, 2012		March 31, 2013
Raw materials and spare parts	$	30,137	$	37,219
Work in process	5,835		3,988
Finished goods	2,180		3,011
Total	$	38,152	$	44,218

Note 8—Land, Property and Equipment

Land, property and equipment at December 31, 2012 and March 31, 2013 are summarized as follows:

	December 31, 2012			March 31, 2013
Land	$	1,476		$	1,476
LNG liquefaction plants	93,384			93,475
RNG plants	23,582			49,843
Station equipment	158,447			162,749
LNG trailers	13,566			18,664
Other equipment	47,143			48,438
Construction in progress	198,916			179,671
	536,514			554,316
Less: accumulated depreciation	(108,337		)	(115,908		)
	$	428,177		$	438,408

As of December 31, 2012 and March 31, 2013, $12,087 and $6,601 are included in accounts payable balances, respectively, which are related to purchases of property and equipment. These amounts are excluded from the condensed consolidated statements of cash flows as they are non-cash investing activities.

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Note 9—Investments in Other Entities

The Company has invested in Clean Energy del Peru (“Peru JV”), a joint venture in Lima, Peru that operates CNG stations. The Company accounted for its investment in Peru JV under the equity method of accounting as the Company had the ability to exercise significant influence over Peru JV’s operations. In March 2013, the Company completed the sale of its entire ownership interest in Peru JV for $6,119 after receiving a dividend distribution of $1,091, and recognized a gain of $4,705.

Note 10—Accrued Liabilities

Accrued liabilities at December 31, 2012 and March 31, 2013 consisted of the following:

	December 31, 2012		March 31, 2013
Salaries and wages	$	4,558	$	5,928
Accrued gas and equipment purchases	10,091		11,699
Derivative liability	112		36
Contingent consideration obligations	70		—
Accrued property and other taxes	4,483		4,524
Accrued professional fees	1,310		1,625
Accrued employee benefits	2,607		3,182
Accrued warranty liability	2,665		2,885
Other	4,898		11,309
	$	30,794	$	41,188

Note 11—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:

	March 31, 2012			March 31, 2013
Warranty liability at beginning of year	$	3,130		$	2,665
Costs accrued for new warranty contracts and changes in estimates for pre-existing warranties	939			879
Service obligations honored	(932		)	(659		)
Warranty liability at end of period	$	3,137		$	2,885

Note 12—Long-term Debt

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 are being primarily 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.

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

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

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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 are placed into various accounts in accordance with the requirements of the Indenture and the Depository Agreement. The funds in these accounts is 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 makes 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 are placed into a Surplus Account (as defined). The funds in the Surplus Account are 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 March 31, 2013, $952 was recorded as long term restricted cash and $8,838 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 March 31, 2013, DCEMB was in compliance with all its debt covenants.

Purchase Notes

In connection with the closing of the Company’s acquisition of IMW, the Company agreed to make future payments consisting of four annual payments in the amount of $12,500 which were subsequently amended to be CAD$5,000 and $7,500. Each payment under the IMW Notes will consist of CAD$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 January 2011, the Company paid $5,000 in cash and $7,500 in shares of its common stock. The Company paid CAD$5,000 in cash in January 2012 and $3,750 in shares of its common stock in each of August 2012 and October 2012. The Company paid CAD$5,000 in cash and $7,500 in shares of its common stock in February 2013. The IMW Notes that were settled with shares of the Company’s common stock are not included in the condensed consolidated statements of cash flows as they are non-cash financing activities.

In connection with the closing of the Company’s acquisition of Northstar, the Company agreed to make future payments consisting of five annual payments in the amount of $700 each with the first payment due December 15, 2011. Each of the first two payments of $700 was paid in December 2011 and 2012, respectively.

In connection with the closing of the Company’s acquisition of the natural gas fuel infrastructure construction business 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 (the “Weaver Notes”). In May 2012, the Company prepaid $125 of the October 2012 payment, and the remaining amount of such payment was paid in October 2012.

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In connection with the closing of the Company’s acquisition of ServoTech on April 30, 2012, the Company paid $1,400 in cash at closing and paid an additional $1,400 in cash on October 31, 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.

HSBC Lines of Credit

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 $13,000 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 March 31, 2013).

(vii) An operating line of credit with a limit of 5,000 Renminbi (“RMB”) (CAD$810) 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 Bangladeshi Taka (CAD$215) operating line of credit bearing interest at 14%.

(ix) A 170,000 Colombian Peso (CAD$95) 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 (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 3.0 to 1.0, 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 1.25 to 1.0. IMW was in compliance with the financial covenants as of March 31, 2013.

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

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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 $150,000 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 $50,000 (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 CHK 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 March 31, 2013, approximately $483 of these funds were included in long term restricted cash as the Company anticipates primarily using the funds to build LNG 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 March 31, 2013, 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 $150,000 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. On March 1, 2012, Springleaf Investments Pte. LTD transferred $24,000 principal amount of the SLG Notes to Baytree Investments (Mauritius) Pte Ltd.

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 an SLG Note was converted by the holder thereof into 66,888 shares of the Company’s common stock. In January and February 2013, $4,030 of principal and accrued interest under an SLG Note was converted by the holder thereof into 268,664 shares of the Company’s common stock. Such conversions were not included in the condensed consolidated statements of cash flows as it is a non-cash financing activity.

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In connection with the SLG Agreements, the Company also entered into a Registration Rights Agreement, dated August 30, 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 March 31, 2013, the Company met its obligations under the SLG Registration Rights Agreement.

GE Loans

On November 7, 2012, the Company, through two wholly owned subsidiaries (the “Borrowers”), entered into a financing arrangement with General Electric Capital Corporation (“GE,” and the agreement governing such arrangement, the “GE Credit Agreement”). Pursuant to the GE Credit Agreement, GE Capital agreed to loan to the Borrowers up to an aggregate of $200,000 to finance the development, construction and operation of two LNG production facilities (individually a “Project” and together the “Projects”), each with an expected production capacity of approximately 250,000 LNG gallons per day. The Company expects to sell the LNG produced by the Projects through America’s Natural Gas Highway, a nationwide network of natural gas truck fueling stations, which the Company is building along major transportation corridors in the United States.

The Borrowers’ ability to obtain loans under the GE Credit Agreement (collectively, “Loans” and, with respect to each Project “Tranche A Loans” and “Tranche B Loans”) for the Projects is subject to the satisfaction of certain conditions, including each of the (i) acquisition of title to, or leasehold interests in, the sites upon which the Projects will be constructed, (ii) receipt of all governmental approvals necessary in connection with the design, development, ownership, construction, installation, operation and maintenance of the Projects, (iii) commitment of all utility services necessary for the construction and operation of the Projects, and (iv) execution of an engineering, procurement and construction contract for each Project by the Company and GE Oil & Gas, Inc.

The GE Credit Agreement further provides that (i) if initial Loans are not made prior to December 31, 2014, the GE Credit Agreement will automatically terminate, (ii) each Project must be completed by the earlier of (a) the date thirty months after the funding of the initial Loans with respect to such Project and (b) December 31, 2016 (with respect to each Project, the “Date Certain”), (iii) the then existing Loans with respect to each Project must be converted into term loans with eight year amortization schedules (“Term Loans”) on or before the Date Certain with respect to such Project (the date of such conversion with respect to each Project, the “Conversion Date”), provided that if such Loans are not converted into Term Loans by the applicable Date Certain, such Loans must be repaid by the applicable Date Certain, (iv) each Term Loan will be due and payable on the eighth anniversary of the Conversion Date with respect to such Term Loan, and (v) at any time prior to the applicable Conversion Date, the Loans may be prepaid in whole, and at any time after the applicable Conversion Date, the Loans may be prepaid in whole or in part. The Company expects the Loans to bear interest at an annual rate equal to the then- current LIBOR rate plus 7.00%, provided that for purposes of the GE Credit Agreement, the then-current LIBOR rate will always be at least 1.00%. The GE Credit Agreement includes various customary covenants, including debt service coverage ratios, and also provides for customary events of default which, if such events occur, would permit or require the Loans to become or to be declared due and payable. As of March 31, 2013, the Company has not drawn any money under the GE Credit Agreement and was in compliance with the financial covenants.

The Loans are secured by (i) a first priority security interest in all of the Borrowers’ assets, including the Projects, and (ii) a pledge of the Borrowers’ outstanding ownership interests. In addition, the Company has executed a guaranty in favor of GE (“Guaranty”), pursuant to which the Company has guaranteed all of the Borrowers’ obligations under the GE Credit Agreement, including repayment of all Loans.

The Company and GE also entered an equity contribution agreement (the “EC Agreement”) pursuant to which the Company agreed to pay at least 25% of the budgeted cost of the Projects and all additional costs that exceed such expected budgeted costs, in each case, in the form of equity contributions to the Borrowers (“Equity Contributions”). The EC Agreement also requires Clean Energy to provide, concurrent with GE’s extension of the initial Loans under the GE Credit Agreement, letter(s) of credit in an amount equal to the Company’s then-current unfunded Equity Contributions.

Concurrently with the execution of the GE Credit Agreement, the Company issued to GE a warrant (“GE Warrant”) to purchase up to 5,000,000 shares of the Company’s common stock (see note 13).

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Long-term debt at December 31, 2012 and March 31, 2013 consisted of the following:

	December 31, 2012			March 31, 2013
IMW Notes	$	23,983		$	11,657
Northstar future payments	1,848			1,879
DCEMB notes	585			585
DCEMB Revenue Bonds (non recourse to the Company)	38,700			38,700
Chesapeake Notes	100,000			100,000
SLG Notes	149,000			145,000
Weaver Notes	680			689
IMW assumed debt	12,661			11,875
Capital lease obligations	3,568			4,557
Total debt and capital lease obligations	331,025			314,942
Less amounts due within one year and short-term borrowings	(30,389		)	(28,851		)
Total long-term debt and capital lease obligations	$	300,636		$	286,091

Note 13—Earnings Per Share

Basic earnings per share is based upon the weighted-average number of shares outstanding during each period. Diluted earnings per share reflects the impact of assumed exercise of dilutive stock options and warrants. In the three months ended March 31, 2013, 5,000,000 shares of common stock related to the GE Warrant were included in the basic and dilutive net loss per share calculation. The information required to compute basic and diluted earnings per share is as follows:

	Three Months Ended March 31,
	2012	2013
Basic and diluted:
Weighted-average number of common shares outstanding	85,677,090	93,132,454

Certain securities were excluded from the diluted earnings per share calculations for the three months ended March 31, 2012 and 2013, respectively, as the inclusion of the securities would be anti-dilutive to the calculation. The amounts outstanding as of March 31, 2012 and 2013 for these instruments are as follows:

	March 31,
	2012	2013
Options	10,903,234	11,994,610
Warrants	2,130,682	2,130,682
Convertible notes	13,164,557	15,995,781
Restricted Stock Units	1,420,000	1,545,000

Note 14—Stock-Based Compensation

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

	Three Months Ended March 31,
	2012		2013
Stock-based compensation expense	$	4,680	$	6,212
Stock-based compensation expense, net of tax	$	4,680	$	6,212

Stock Options

The following table summarizes the Company’s stock option activity during the three months ended March 31, 2013:

	Number of Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value
Outstanding, December 31, 2012	12,083,677		$	11.75
Options exercised	(28,188	)	6.31
Options forfeited	(60,879	)	13.81
Outstanding, March 31, 2013	11,994,610		$	11.76	6.28	$	14,873
Exercisable, March 31, 2013	8,567,618		$	10.28	5.21	$	23,304

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As of March 31, 2013, there was $21,539 of total unrecognized compensation cost related to non-vested shares. That cost is expected to be recognized over a weighted average period of 1.4 years. The total fair value of shares vested during the three months ended March 31, 2013 was $7,609.

The Company plans to issue new shares to its employees upon the employees’ exercise of their options. The intrinsic value of all options exercised during the three months ended March 31, 2012 and 2013 was $12,955 and $252, respectively.

The Company recorded $3,342 and $4,007 of stock option expense during the three months ended March 31, 2012 and 2013, respectively. The Company has not recorded any tax benefit related to its stock option expense.

Restricted Stock Units

The Company issued 1,545,000 restricted stock units (“RSUs”) to certain key employees during 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 of the RSU, 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.

As of March 31, 2013, there was $7,548 of total unrecognized compensation cost related to non-vested units. That cost is expected to be recognized over a weighted average period of 0.9 years. The Company recorded $1,338 and $2,205 of expense during the three months ended March 31, 2012 and 2013, respectively, related to the RSUs. The Company has not recorded any tax benefit related to its RSU expense.

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

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

Note 16—Income Taxes

The Company’s income tax provision for the three months ended March 31, 2013 was $1,805, which includes a discrete tax expense of $1,409 related to the sale of the Company’s interest in Peru JV during the period. The effective tax rate for the three month periods ended March 31, 2012 and 2013 are different from the federal statutory tax rate primarily as a result of losses for which no tax benefit has been recognized.

The Company did not record a change in its liability for unrecognized tax benefits or penalties in the three months ended March 31, 2012 or March 31, 2013, and the net interest incurred was immaterial for such periods.

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Note 17—Fair Value Measurements

The Company follows the 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 three months ended March 31, 2013, 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 projected financial results for the respective entities, discounted to reflect the time value of money, to value its contingent consideration obligations which are considered to be Level 3 fair value measurements. The fair market value of the Company’s debt instruments approximated their carrying values at March 31, 2013. 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 has been 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 3.08 years as of March 31, 2013. 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 measurement in the table below.

The following tables provide information by level for assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2012 and March 31, 2013, respectively:

Description	Balance at December 31, 2012		Level 1		Level 2		Level 3
Assets:
Available-for-sale securities(1):
Certificate of deposits	$	10,021	$	—	$	10,021	$	—
Municipal bonds and notes	23,650		—		23,650		—
Corporate bonds	4,504		—		4,504		—
Liabilities:
Natural gas futures contracts(2)	107		—		107		—
Contingent consideration obligation(3)	1,516		—		—		1,516
Series I warrants(4)	8,102		—		—		8,102

Description	Balance at March 31, 2013		Level 1		Level 2		Level 3
Assets:
Available-for-sale securities(1):
Certificate of deposits	$	10,062	$	—	$	10,062	$	—
Municipal bonds and notes	23,540		—		23,540		—
Zero coupon bonds	124		—		124		—
Corporate bonds	4,240		—		4,240		—
Liabilities:
Natural gas futures contracts(2)	2		—		2		—
Contingent consideration obligation(3)	1,516		—		—		1,516
Series I warrants(4)	8,568		—		—		8,568

(1) Included in short-term investments in the condensed consolidated balance sheets. See note 4 for further information.

(2) See note 5 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.

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

Liabilities: Contingent Consideration	March 31, 2012			March 31, 2013
Beginning Balance	$	5,978		$	1,516
Total gain included in SG&A expense	(2,648		)	—
Ending Balance	$	3,330		$	1,516

Liabilities: Series I Warrants	March 31, 2012		March 31, 2013
Beginning Balance	$	11,493	$	8,102
Total loss included in earnings	13,506		466
Ending Balance	$	24,999	$	8,568

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.

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 based on the payout structure using the following inputs as of March 31, 2013:

Unobservable Input		Range or Weighted Average
Gross profit projection		$16,321–$32,641
Probability of reaching target gross profit		0.0%–40.0%

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.

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 March 31, 2013:

Unobservable Input		Range or Weighted Average
Current market price of the Company’s common stock		$13.00
Exercise price of the warrant		$12.68
Dividend yield		0.00%
Remaining term of the warrant		3.08
Implied volatility of the Company’s common stock		43.2%–46.5%
Assumed discount rate		Simple average 0.4%

Significant changes in any of those inputs in 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, an increase in the volatility of the Company’s

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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 ended March 31, 2012 and 2013. 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 18—Recently Adopted Accounting Changes and Recently Issued Accounting Standards

On January 1, 2013, the Company adopted Accounting Standards Update (“ASU”) No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (ASU 2013-02). The ASU requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items into net income if the amount being reclassified is required under US GAAP to be reclassified in its entirety to net income. An entity shall provide this information together, in one location, in either of the following ways: a) on the face of the statement where net income is presented, or b) as a separate disclosure in the notes to the financial statements. The gain or loss resulting from the settlement of the Company’s futures contracts is the only significant item being reclassified during the three-month periods ended March 31, 2012 and 2013. The Company has disclosed this information in note 5.

Note 19—Volumetric Excise Tax Credit (VETC)

On January 2, 2013, the American Taxpayer Relief Act was signed into law which extended VETC through December 31, 2013 and made it retroactive to January 1, 2012. 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 recognized during the three month period ended March 31, 2013 was $26,217, which includes $20,800 for the 2012 VETC credits.

Note 20 — Subsequent Events

On April 25, 2013 (“Closing Date”), Mavrix, LLC (“Issuer”), a newly-formed special purpose vehicle subsidiary of Clean Energy Renewable Fuels, LLC (“CERF”), entered a Note Purchase Agreement (“NPA”) with Massachusetts Mutual Life Insurance Company (“Note Purchaser”). CERF and Issuer are subsidiaries of the Company. Issuer owns all of the equity interests in Canton Renewables, LLC (“Canton”) and 70% of the equity interests in Dallas Clean Energy, LLC, which owns all of the equity interests in Dallas Clean Energy McCommas Bluff, LLC (“DCEMB,” and together with Canton, the “Project Companies”). Canton owns a RNG extraction and processing project at the Sauk Trail Hills Landfill in Canton, Michigan and DCEMB owns the RNG extraction and processing project at the McCommas Bluff Landfill in Dallas, Texas.

Pursuant to the NPA, on the Closing Date, Note Purchaser (i) purchased a secured multi-draw promissory note (“Mavrix Note”) from Issuer in the maximum aggregate principal amount of $30,000,000 (the “Maximum Principal Amount”), and (ii) funded an initial advance of $5,000,000 under the Mavrix Note. Subject to the Issuer and the Project Companies satisfying certain conditions described in the NPA, Note Purchaser will make additional advances under the Mavrix Note, up to the Maximum Principal Amount. Issuer will use the proceeds from the sale of the Mavrix Note and any advances thereunder to (x) pay any transaction costs and fees related to the NPA and the issuance of the Mavrix Note and (y) make distributions to its direct and indirect parent companies. The Issuer’s direct and indirect parent companies plan to use such distributions to finance construction of additional RNG extraction and processing projects and for working capital purposes.

The Mavrix Note matures 12 years from the Closing Date and bears base interest at the rate of 12% per annum and paid in kind interest at the rate of 2.0% per annum. The principal amount of the Mavrix Note will be repaid in 28 quarterly installments commencing on June 30, 2018, provided that the NPA requires mandatory prepayment of such principal amount upon certain casualty or condemnation events, assets sales or extraordinary transactions. In addition, the Issuer may not voluntarily repay the Mavrix Note until the third anniversary of the Closing Date and, subject to the foregoing restriction, the Issuer must pay a prepayment premium if it prepays the Mavrix Note prior to the ninth anniversary of the Closing Date.

The Mavrix Note is secured by (i) a first priority security interest in all of Issuer’s assets and (ii) a pledge of Issuer’s outstanding equity interests. In addition, the NPA includes various customary affirmative and negative covenants and also provides for customary events of default which, if such events occur, would permit or require the Mavrix Note to become, or to be declared, due and payable. The Mavrix Note is non-recourse to the Company.

On May 6, 2013 (the “Acquisition Date”), Clean Energy (“Clean Energy”), a wholly owned subsidiary of the Company, entered into a Stock Purchase Agreement (the “Purchase Agreement”) with Mansfield Energy Corp. (“Mansfield”) and its wholly owned subsidiary Mansfield Gas Equipment Systems Corporation (“MGES”). Under the terms of the Purchase Agreement, on the Acquisition Date, Clean Energy purchased from Mansfield all of the issued and outstanding capital stock of MGES for $20,000,000, paid 50% in cash and 50% in shares of the Company’s common stock (the “Shares”). The Purchase Agreement also provides for Mansfield to receive additional consideration if Closing Working Capital (as defined in the Purchase Agreement) is greater than $3,000,000. MGES is primarily engaged in the business of providing CNG station design and construction and CNG equipment repair and maintenance services.

Mansfield further agreed that, for a period beginning on the Acquisition Date and ending on October 16, 2013 (the “Lock-Up Expiration Date”), it will not sell, transfer or make any other disposition of all or any portion of the Shares. Clean Energy agreed to file with the Securities and Exchange Commission (“SEC”) a registration statement covering the resale of the Shares and to cause such registration statement to be declared effective by the SEC on or before the Lock-Up Expiration Date. In addition, the Agreement provides that Mansfield will, subject to certain limitations, indemnify Clean Energy for damages and losses incurred or suffered by Clean Energy as a result of, among other things, breaches of Mansfield’s and MGES’ representations, warranties and covenants contained in the Purchase Agreement.

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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, 2012 contained in our 2012 Annual Report on Form 10-K filed with the SEC on February 28, 2013, as well as the 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 2012 Annual Report on Form 10-K (the”2012 10-K”). In preparing this MD&A, we presume that readers have access to and have read the MD&A in our 2012 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 are the leading provider of natural gas as an alternative fuel for vehicle fleets in the United States and Canada, based on the number of stations operated and the amount of gasoline gallon equivalents of compressed natural gas (“CNG”) and liquefied natural gas (“LNG”) delivered. We design, build, operate and maintain fueling stations and supply our customers with CNG fuel for light, medium and heavy-duty vehicles and LNG fuel for medium and heavy-duty vehicles. We also sell non-lubricated natural gas compressors and related equipment used in CNG stations and LNG stations, convert light and medium duty vehicles to run on natural gas, provide design and engineering services for natural gas engine systems, produce renewable natural gas (“RNG”), which can be used as vehicle fuel or sold for power generation, and sell tradable credits we generate by selling natural gas and RNG as a vehicle fuel, including credits we generate under the California Low Carbon Fuel Standard (“LCFS Credits”) and Renewable Idenfiication Numbers (“RIN Credits”) we generate under the federal Renewable Fuel Standard Phase 2. In addition, we help our customers acquire and finance natural gas vehicles and obtain local, state and federal grants and incentives.

Overview

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

Sources of revenue. We generate revenues by selling CNG and LNG, providing operations and maintenance (“O&M”) services to our vehicle fleet customers, designing and constructing fueling stations and selling or leasing those stations to our customers, selling RNG, selling converted natural gas vehicles, providing design and engineering services for natural gas engine systems, selling non-lubricated natural gas fueling compressors and related equipment and maintenance services, providing financing for our customers’ natural gas vehicle purchases and selling tradable credits, including LCFS Credits and RIN Credits.

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Key operating data. In evaluating our operating performance, our management focuses primarily on: (1) the amount of CNG and LNG gasoline gallon equivalents delivered (which we define as (i) the volume of gasoline gallon equivalents we sell to our customers, plus (ii) the volume of gasoline gallon equivalents dispensed to our customers at stations where we provide 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 (through March 2013 when we sold our interest in the 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 our RNG production facilities, (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 2012 Annual Report on Form 10-K, presents our key operating data for the years ended December 31, 2010, 2011, and 2012 and for the three months ended March 31, 2012 and 2013:

Gasoline gallon equivalents delivered (in millions)	Year Ended December 31, 2010	Year Ended December 31, 2011	Year Ended December 31, 2012	Three Months Ended March 31, 2012	Three Months Ended March 31, 2013
CNG	81.4	101.8	130.5	29.0	34.0
RNG	7.4	6.7	8.9	2.1	2.2
LNG	33.9	47.1	55.5	12.6	13.7
Total	122.7	155.6	194.9	43.7	49.9

Operating data
Gross margin	$	69,945		$	76,033		$	80,324		$	17,748		42,302	(1)
Net loss attributable to Clean Energy Fuels. Corp	(2,516		)	(47,633		)	(101,255		)	(31,905		)	(3,871	)(1)

(1) See discussion under “Operations — Government Incentives” below.

Key trends in 2010, 2011, 2012 and the first three months of 2013. According to the EIA, demand for natural gas fuels in the United States increased by approximately 19% during the period January 1, 2010 through December 31, 2012. 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 358 at March 31, 2013 (an 82.7% 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 2010 to 2012 increased by 58.8%. The increase in gasoline gallon equivalents delivered was the primary contributor to increased revenues during 2010, 2011 and 2012. In addition, beginning in 2011, we also benefitted from increased revenues from compressor sales and fueling station installations as a result of our acquisitions of IMW Industries, Ltd. (“IMW”) and Wyoming Northstar Incorporated and its affiliated companies (“Northstar”), which occurred during the third and fourth quarters of 2010.

Our fuel 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 2010 through 2012 and the first quarter of 2013. Starting in 2011, the cost of sales related to compressors sold through IMW and fueling station installations performed by Northstar also contributed to the increase. Cost of sales can vary between periods due to timing of station construction sale activity.

Since the last half of 2009, we have experienced reduced margins in certain markets, particularly in the municipal transit and refuse sectors. 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 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 in 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.

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During 2012 and the first three months in 2013, 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 $97.23 per barrel on March 31, 2013. In California, average retail prices for gasoline were $3.68 per gallon in January 2012, hit a high of $4.71 per gallon in October 2012, and settled at $4.11 per gallon at March 31, 2013. Average retail prices for diesel fuel in California were $4.05 per diesel gallon in January 2012, hit a high of $4.50 per diesel gallon in September 2012, and settled at $4.15 per diesel gallon at March 31, 2013. Higher gasoline and diesel prices improve our margins on fuel sales to the extent we price our fuel at a discount to gasoline or diesel and natural gas prices do not increase by a corresponding amount. During this time period, the price for natural gas increased slightly. The NYMEX price for natural gas fluctuated from $3.08 per MMbtu in January 2012 to $3.71 per MMbtu in December 2012, and settled at $3.43 per MMbtu in March 2013. The average retail sales price of our CNG fuel sold in the Los Angeles metropolitan area ranged from $2.75 per gallon for the month of January 2012 to $2.90 per gallon for the month of March 2013. The average retail sales price of our LNG fuel sold in the Los Angeles metropolitan area ranged from $2.48 per gallon during January 2012 to $2.70 per gallon for the month of March 2013.

Recent developments. In January 2013, certain federal fuel tax credits were extended through December 31, 2013 and made retroactive to January 1, 2012. The amount attributed to 2012, $20.8 million, has been recorded by us in the first quarter of 2013, the period in which the law was passed. In March 2013, we sold our ownership interest in our joint venture in Peru for approximately $6.1 million after receiving a dividend distribution of approximately $1.1 million (see note 9 to our condensed consolidated financial statements). In January and February 2013, an aggregate of $4.0 million of principal and accrued interest under an SLG Note (as defined and discussed elsewhere in this Item 2 and in note 12 to our condensed consolidated financial statements) was converted by the holder into 268,664 shares of our common stock.

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 in recent years.

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 acquisitions of IMW and Northstar, we are 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 U.S. heavy-duty over-the-road (“OTR”) 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 U.S. 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 truck per year, and the lower cost of natural gas compared to regular gasoline and diesel would result in substantial fuel savings for the operator. With over eight million heavy-duty trucks registered in the U.S. market, we 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 natural gas 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 America’s Natural Gas Highway to initially include approximately 150 truck fueling stations, of which 70 ANGH stations were completed at the end of 2012. Of these 70 stations, seven are open and selling LNG, and the remainder are planned to open as natural gas engines that are well-suited for the trucking market (including the CWI 11.9 liter engine) become available and trucks powered by such engines are deployed in the geographic areas where the stations are located. We expect to build approximately 40 - 60 additional ANGH stations in 2013, depending upon the deployment of natural gas trucks, demand for LNG, and our ability to identify and obtain suitable locations for LNG stations, among other things. Many ANGH stations are located at Pilot-Flying J Travel Centers already serving goods movement trucking.

Many governmental entities, which represented approximately 27.2% of our revenues from 2010 through March 31, 2013, are experiencing significant budget deficits 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.

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

Our business plan calls for approximately $139.5 million in capital expenditures from April 1, 2013 through the end of 2013, primarily related to construction of new fueling stations, including ANGH stations, expanding and constructing our LNG plants, 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, and to make capital expenditures to build additional LNG production facilities or to otherwise secure future LNG supply. 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.

Operations

We generate revenues principally by selling CNG and LNG and providing O&M services to our vehicle fleet customers. For the three months ended March 31, 2013, CNG and RNG (together) represented 73% and LNG represented 27% 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 revenues through sales of RNG, sales of natural gas vehicles, sales of advanced natural gas fueling compressors and related equipment and maintenance services, providing financing for our customers’ natural gas vehicle purchases, and selling RIN and LCFS Credits.

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 principally determined 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 Production and Sales

We obtain LNG from our own plants as well as through relationships with suppliers. We own and operate LNG liquefaction plants near Houston, Texas and Boron, California, and we plan to build two new LNG plants in connection with our strategic collaboration with GE. We expect that these additional plants, as well as our planned expansion of our Boron, California plant, and other plants to be built by us or third parties in the future, will be necessary to secure sufficient sources of LNG.

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. During 2012, we procured 44% of our LNG from third- party producers, and we produced the remainder of the LNG at our liquefaction plants in Texas and California. We expect to enter additional purchase contracts with third party LNG producers in the future. For LNG that we purchase from third parties, we have entered into, and may enter into additional “take or pay” contracts that require us to purchase minimum volumes of LNG at index- based rates. We deliver LNG via our fleet of 80 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.

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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 condensed consolidated statements of operations as the credits are fully refundable and do not need to offset tax liabilities to be received. As such, the credits are not deemed income tax credits under the accounting guidance applicable to income taxes. In addition, we believe the credits are properly recorded as revenue because we often incorporate the tax credits into our pricing with our customers, thereby lowering the actual price per gallon we charge them.

The American Taxpayer Relief Act, signed into law on January 2, 2013, provided a one-year extension for several tax credits affecting alternative fuels, including the $0.50 per gallon alternative-fuel tax credit for CNG and LNG. The tax credits were extended through December 31, 2013 and also made retroactive to January 1, 2012. VETC revenues recognized during the three month period ended March 31, 2013 were $26.2 million, which includes $20.8 million for CNG and LNG we sold in 2012.

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.

Vehicle Acquisition and Finance

We offer 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 March 31, 2013, we have not generated significant revenue from vehicle financing activities.

RNG

We own a 70% interest in a RNG production facility at the McCommas Bluff landfill located in Dallas, Texas. We sell RNG produced at the facility to Shell Energy North America (US) L.P. under a gas sale agreement and, depending upon RNG production volumes, we have the ability to sell RNG as a vehicle fuel. We own a second RNG production facility located at a Republic Services landfill in Canton, Michigan. This facility was completed in 2012, and we have entered into a ten-year fixed-price sale contract for the majority of the RNG that we expect the facility to produce (the effectiveness of such contract is subject to the California Energy Commission (“CEC”) certifying the facility). We are building a third RNG facility at a Republic Services landfill in North Shelby, Tennessee, and we expect the facility to be operational during the first quarter of 2014. We are seeking to expand our RNG business by pursuing additional RNG production projects. We sell some of the RNG we currently produce, and expect to sell a significant amount of the RNG we produce at the facilities we are building and plan to build, through our natural gas fueling infrastructure for use as a vehicle fuel. In addition, we plan to purchase RNG from third party producers, and sell that RNG for vehicle use through our fueling infrastructure.

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Vehicle Conversions

Our subsidiary, BAF Technologies, Inc. (“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 standards of both the Environmental Protection Agency and the California Air Resources Board achieving Super Ultra Low Emission Vehicle emissions. In 2012, we completed our purchase of all of ServoTech Engineering, Inc. (“ServoTech”). ServoTech provides, among other services, design and engineering services for natural gas engine systems. We generate revenues through the sale of natural gas vehicles that have been converted to run on natural gas by BAF, and design and engineering services for natural gas engine systems by ServoTech. For the three months ended March 31, 2012 and 2013, BAF and ServoTech combined contributed approximately $8.3 million, and $4.2 million, respectively, to our revenue.

Natural Gas Fueling Compressors

Our subsidiary, IMW, manufactures and services 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 three months ended March 31, 2012 and 2013, IMW contributed approximately $13.5 million and $17.6 million, respectively, to our revenue.

Sales of RIN and LCFS Credits

We generate LCFS Credits when we sell RNG and conventional natural gas for use as a vehicle fuel in California, and we generate RIN Credits when we sell RNG for use as a vehicle fuel. We can sell these RIN and LCFS Credits to third parties who need the RIN and LCFS Credits to comply with federal and state requirements. In 2012, we realized $2.9 million in revenue through the sale of LCFS Credits. During the three months period ended March 31, 2013, we realized $0.7 million and $0.2 million in revenue through the sale of LCFS and RIN Credits, respectively. We anticipate that we will generate and sell increasing numbers of RIN and LCFS Credits as we grow our business and sell escalating amounts of CNG, LNG and RNG for use as a vehicle fuel.

Volatility of Earnings and Cash Flows

During 2012 and the first three months of 2013, 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 March 31, 2013, we had paid $0.6 million in margin deposits, which are included in prepaid expenses and other current assets in our condensed consolidated balance sheet.

Volatility of Earnings Related to Series I Warrants

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 of $13.5 million and $0.5 million related to recording the estimated fair value changes of our Series I warrants in the three months ended March 31, 2012 and 2013, respectively. See note 17 to our condensed consolidated financial statements contained 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. As of March 31, 2013, 2,130,682 of the Series I warrants remained outstanding.

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Volatility of Earnings Related to Contingent Consideration

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

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 three months of 2012 we recognized a gain of $2.6 million related to the estimated change in value of the IMW contingent consideration. There was no change in the value of the IMW contingent consideration during the first three months of 2013 and therefore no gain or loss was recorded. 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 12 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 March 31, 2013.

The indenture and the loan agreement entered into by Dallas Clean Energy McCommas Bluff, LLC (“DCEMB”), our 70% owned subsidiary, as part of issuing its Revenue Bonds, as defined and disclosed in note 12 to our condensed consolidated financial statements, have certain non-financial debt covenants with which DCEMB must comply. As of March 31, 2013, DCEMB was in compliance with its debt covenants.

The loan agreement we entered into as part of issuing the CHK Notes, as defined and discussed elsewhere in note 12 to our condensed consolidated financial statements, has certain non-financial debt covenants with which we must comply. As of March 31, 2013, 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 12 to our condensed consolidated financial statements, have certain non-financial debt covenants with which we must comply. As of March 31, 2013, we were in compliance with these covenants.

The GE Credit Agreement, as defined and discussed in note 12 to our condensed consolidated financial statements, contains certain covenants with which we must comply. As of March 31, 2013, we were in compliance with these covenants.

Risk Management Activities

Our risk management activities, including the revised natural gas hedging policy, are discussed in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) of our 2012 Annual Report on Form 10-K. For the quarter ended March 31, 2013, there were no material changes to our risk management activities.

Critical Accounting Policies

For the three months ended March 31, 2013, 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 2012 Annual Report on Form 10-K.

Recently Issued Accounting Pronouncements

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

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Results of Operations

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

	Three Months Ended March 31,
	2012		2013
Statement of Operations Data:
Revenue:
Product revenues	89.3	%	89.7	%
Service revenues	10.7		10.3
Total revenues	100.0		100.0
Operating expenses:
Cost of sales:
Product cost of sales	70.5		50.3
Service cost of sales	5.4		4.2
Derivative loss on Series I warrant valuation	18.3		0.5
Selling, general and administrative	33.7		35.3
Depreciation and amortization	11.1		10.9
Total operating expenses	139.0		101.2
Operating loss	(39.0	)	(1.2	)
Interest expense, net	(5.0	)	(5.5	)
Other income (expense), net	1.1		(0.4	)
Income (loss) from equity method investment	0.1		(0.1	)
Gain from sale of equity method investment	—		5.1
Loss before income taxes	(42.8	)	(2.1	)
Income tax expense	(0.3	)	(1.9	)
Net loss	(43.1	)	(4.0	)
Income of noncontrolling interest	(0.2	)	0.0
Net loss attributable to Clean Energy Fuels Corp.	(43.3	)	(4.0	)

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2013

Revenue. Revenue increased by $19.4 million to $93.0 million in the three months ended March 31, 2013, from $73.6 million in the three months ended March 31, 2012. A portion of this increase was the result of an increase in the number of gallons delivered between periods from 43.7 million gasoline gallon equivalents to 49.9 million gasoline gallon equivalents. The increase in volume was primarily from an increase in CNG sales of 5.0 million gallons. Our net increase in CNG volume was primarily from 15 new refuse customers, six new airport customers, three new transit customers and one new trucking customer, which together accounted for 3.5 million gallons of the CNG volume increase between periods. We also experienced an increase of 1.5 million gallons in CNG volume between periods from our existing airport, refuse and trucking customers, combined with the volume growth from our share of our joint venture in Peru. Further, we experienced an increase of 1.1 million gallons in LNG volume between periods, which was primarily from two new trucking customers, two new industrial customers, two new transit customers and one new refuse customer. We experienced an increase in our RNG sales (primarily through our 70% share of the RNG sales at DCEMB) of 0.1 million gallons between periods due to increased RNG production at DCEMB’s facility. Revenue attributable to VETC increased by $26.2 million between periods, including $20.8 million related to recording all the 2012 VETC revenue in the first quarter of 2013, as a result of legislation passed in January 2013 that made the fuel tax credits retroactive to January 1, 2012 and extended them to December 31, 2013. Revenue attributable to IMW increased between periods by $4.1 million. Also contributing to the revenue increase between periods were $0.9 million of LCFS Credits and RIN Credits that we recognized during the period. These increases were offset by a $12.2 million decrease in station construction revenue between periods. We also experienced a slight decrease in our effective price per gallon that we charged to our customers between periods. Our effective price per gallon charged was $0.83 in the three months ended March 31, 2013, which represents a $0.01 per gallon decrease from $0.84 per gallon in the three months ended March 31, 2012. Revenue also decreased by $4.1 million between periods due to decreased sales of natural gas vehicle equipment and emission control services by BAF.

Cost of sales. Cost of sales decreased by $5.2 million to $50.7 million in the three months ended March 31, 2013, from $55.9 million in the three months ended March 31, 2012. Our cost of sales primarily decreased between periods as a result of $11.6 million in decreased station construction costs between periods. We also experienced a $1.8 million decrease in costs related to BAF’s vehicle equipment sales and emission control services between periods as BAF’s sales of natural gas vehicle equipment decreased. These decreases were offset by the increase in our cost of sales between periods as a result of delivering more volume to our customers. Cost of sales that IMW incurred increased between periods by $4.8 million due to their increased sales between periods. Our effective cost per gallon was $0.55 per gallon for both periods.

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Derivative loss on Series I warrant valuation. Derivative loss decreased by $13.0 million to $0.5 million in the three months ended March 31, 2013, from $13.5 million in the three months ended March 31, 2012. The 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 17 to our condensed consolidated financial statements contained elsewhere herein.)

Selling, general and administrative. Selling, general and administrative increased by $8.0 million to $32.9 million in the three months ended March 31, 2013, from $24.9 million in the three months ended March 31, 2012. The increase was primarily related to our continued business growth. Salaries and employee benefits increased by $2.9 million between periods, primarily due to higher average salaries and benefits per employee during the first quarter of 2013 compared to 2012, as we increased our sales force by 26 and hired more management level positions to help support America’s Natural Gas Highway and our continued business expansion. Related to our growth, we experienced a $1.0 million increase in consulting, legal, business insurance, rent and occupancy, travel and entertainment, and employee recruiting expenses between periods. Also contributing to the increase between periods was the effect of recording $2.7 million of lower gains on the IMW contingent consideration and an increase in our stock based compensation expense of $1.5 million in the three months ended March 31, 2013.

Depreciation and amortization. Depreciation and amortization increased by $2.1 million to $10.2 million in the three months ended March 31, 2013, from $8.1 million in the three months ended March 31, 2012. This increase was primarily due to additional depreciation expense in the three months ended March 31, 2013 related to increased property and equipment balances between periods, primarily related to our expanded station network, including our build-out efforts of America’s Natural Gas Highway. In addition, our amortization expense in the three months ended March 31, 2013 includes increased amortization expense related to our ServoTech acquisition that we completed on April 30, 2012.

Interest expense, net. Interest expense, net, increased by $1.4 million to $5.1 million for the three months ended March 31, 2013, from $3.7 million for the three months ended March 31, 2012. This increase was primarily the result of an increase in interest expense related to the $50 million of convertible notes we issued in July 2012. (See note 12 to our condensed consolidated financial statements for a description of our outstanding debt).

Other income (expense), net. Other income (expense), net, decreased by $1.2 million to $0.4 million of expense for the three months ended March 31, 2013, compared to $0.8 million of income for the three months ended March 31, 2012. This decrease was primarily due to foreign currency exchange rate changes between periods on our IMW purchase notes.

Income from equity method investment. During the three months ended March 31, 2013, we recorded $0.1 million of equity in the loss of our 49% interest in our Peruvian joint venture, compared to $0.1 million of equity in the income during the of the three months ended March 31, 2012. We sold our interest in our Peruvian joint venture in March 2013.

Gain from sale of equity method investment. During the three months ended March 31, 2013, we recorded $4.7 million gain from sale of our 49% interest in our Peruvian joint venture.

Income of noncontrolling interest. During the three months ended March 31, 2012 and 2013, we recorded and $0.1 million and $0.04 million, respectively, for the noncontrolling interest in the net income of DCEMB. The noncontrolling interest represents the 30% interest of 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.

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Liquidity

Cash used in operating activities was $16.9 million for both the three months ended March 31, 2013 and 2012. During the three months ended March 31, 2013, we recognized $26.2 million of VETC revenue, of which $20.8 million related to 2012 as VETC was extended in January 2013 and also made retroactive to January 1, 2012. None of the 2013 VETC amounts were collected as of March 31, 2013. During the three months ended March 31, 2012, we collected $1.2 million in VETC receivables related to 2011 VETC amounts. During the three months ended March 31, 2013, we received a $1.1 million repayment of a note receivable and a $1.1 million dividend distribution from our Peruvian joint venture. We also experienced other working capital changes between periods due to timing differences related to various cash flows.

Cash used in investing activities was $2.9 million for the three months ended March 31, 2013, compared to $32.0 million for the three months ended March 31, 2012. We purchased property and equipment for $21.7 million in the three months ended March 31, 2013, which is a decrease of $14.9 million from $36.6 million paid to purchase property and equipment in the three months ended March 31, 2012. This decrease is primarily related to our slowing the pace of ANGH-related construction activity as we seek to time such construction with commercial adoption of natural gas engines, including the Cummins-Westport 11.9 liter engine, that are well-suited for the U.S. heavy-duty trucking market. During both periods, restricted cash decreased as we funded the construction of America’s Natural Gas Highway and certain RNG projects. During the three months ended March 31, 2013, we received $6.1 million related to the sale of our Peruvian joint venture. The loans we made to our customers to assist them in purchasing natural gas vehicles decreased to $0.4 million in the three months ended March 31, 2013, from $3.1 million in the three months ended March 31, 2012. During the three months ended March 31, 2013 and 2012, we also collected on and sold $2.3 million and $2.6 million, respectively, of loans previously made to our customers. Additionally, other than reinvesting the proceeds from matured short-term investments, we did not purchase incremental short-term investments during the three months ended March 31, 2013, compared to purchases of $4.6 million during the three months ended March 31, 2012.

Cash used in financing activities for the three months ended March 31, 2013 was $5.9 million, compared to $0.5 million provided by financing activities for the three months ended March 31, 2012. This decrease was primarily caused by a reduction in the proceeds we received from the exercise of employee stock options of $5.7 million between periods.

Our financial position and liquidity are, and will be, influenced by a variety of factors, including our ability to generate cash flows from operations, 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 costs, 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 March 31, 2013, we had total cash and cash equivalents of $82.6 million, compared to $108.5 million at December 31, 2012.

On November 7, 2012, we, through two wholly owned subsidiaries (the “Borrowers”), entered into the GE Credit Agreement. Pursuant to that Agreement, GE agreed to loan to the Borrowers up to an aggregate of $200.0 million to finance the development, construction and operation of two LNG production facilities, each with an expected production capacity of approximately 250,000 LNG gallons per day.

Capital Expenditures

Our business plan calls for approximately $139.5 million in capital expenditures from April 1, 2013 through the end of 2013, primarily related to construction of new fueling stations, including stations along ANGH, construction and expansion of our LNG plants, 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 raise 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.

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Off-Balance Sheet Arrangements

At March 31, 2013, 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 $54.0 million,

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

· operating leases where we are the lessee,

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

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

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

We have 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 $0.2 million per year, plus up to $0.1 million per year for each 30 million gallons of production capacity utilized, subject to future adjustment based on consumer price index changes. We must also pay a royalty to the landlord for each gallon of LNG produced at the facility, as well as a fee for certain other services that the landlord will provide.

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

Item 3.—Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Risk. We are subject to market risk with respect to our sales of natural gas, which has historically been subject to volatile market conditions. Our exposure to market risk is heightened when we have a fixed price 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 16% (or 21% excluding BAF, IMW and Northstar) of our cost of sales for 2012 and 24% (or 33% excluding BAF, IMW and Northstar) for the three months ended March 31, 2013.

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 see “—Risk Management Activities” above.

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We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to the futures contracts we hold as of March 31, 2013 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 March 31, 2013 ($3.43 per Mcf), we could expect a corresponding fluctuation in the value of the contracts of approximately $0.02 million.

Foreign exchange rate risk. Because we have foreign operations, we are exposed to foreign currency exchange gains and losses. Since the functional currency of our foreign operations is in their local currency, the currency effects of translating the financial statements of those foreign subsidiaries, which operate in local currency environments, are included in the accumulated other comprehensive income (loss) component of consolidated equity and do not impact earnings. However, foreign currency transaction gains and losses not in our subsidiaries’ functional currency do impact earnings and resulted in approximately $0.5 million of losses for the three months ended March 31, 2013. During the three months ended March 31, 2013, 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 March 31, 2013, we would expect a corresponding fluctuation in the value of the assets and liabilities of approximately $0.4 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 Securities Exchange Act of 1934, as amended (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 or results of operations. However, we believe that the ultimate resolution of such actions will not have a material adverse effect on our consolidated financial position, results of operations, or liquidity.

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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 quarterly report on Form 10-Q 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 three months ended March 31,2013, we incurred pre-tax losses of $2.0 million, which included a derivative loss of $0.5 million related to marking to market the value of our Series I warrants. In 2010, 2011 and 2012, we incurred pre-tax losses of $4.2 million, $48.2 million, and $99.6 million, respectively. Our loss for 2010 was decreased by a derivative gain of $10.3 million on our Series I warrants; our loss for 2011 includes a $2.7 million derivative gain; and our loss for 2012 includes a $3.4 million derivative gain. During 2010 and 2011, our losses were substantially decreased by our receipt of approximately $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; however, the American Taxpayer Relief Act (which was signed into law on January 2, 2013) reinstated such program retroactive to January 1, 2012 and extended it through December 31, 2013. We recognized $20.8 million of revenue from the federal fuel tax credits related to 2012 during the first quarter of 2013. 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.

If commercial introduction of the CWI 11.9 liter engine is further delayed, or if the engine is not adopted by truck operators as we anticipate, our results of operations and business prospects will be adversely affected.

We believe that our entry into the heavy duty truck market, and the execution of our ANGH initiative, depends upon the successful launch of the CWI 11.9 liter engine (or a comparable engine that we believe would be well-suited for the U.S. heavy-duty OTR trucking market). The launch of this engine has been previously delayed and may be further delayed, and we have no control over when the engine will become commercially available. Further, if the CWI 11.9 liter engine becomes commercially available, it may not be adopted and deployed by heavy-duty truck operators in sufficient numbers to justify building America’s Natural Gas Highway. Heavy-duty trucks powered by the engine will cost more, as compared to comparable diesel trucks, and may experience operational or performance issues. If the CWI 11.9 liter engine does not become commercially available or if meaningful numbers of the engine are not deployed, our business and financial results could be harmed.

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, a network of natural gas truck fueling stations on interstate highways and in major metropolitan areas. 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:

· We have no influence over when natural gas trucks powered by engines that are well-suited for the United States heavy duty truck market (including the Cummins-Westport 11.9 liter engine) will become commercially available;

· Operators may not adopt heavy-duty natural gas trucks due to cost, actual or perceived performance issues, or other factors that are outside our control;

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

· Development of America’s Natural Gas Highway will require substantial additional 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;

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· We may not be able to hire and retain the necessary qualified personnel, and our operational infrastructure and systems may be inadequate;

· We may complete ANGH stations before there are sufficient numbers of customers who are capable of fueling at the stations, and if such customers do not materialize, we will have substantial investments in assets that do not produce revenues and we may lose money on LNG fuel that is supplied to the 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 the fuel of choice for the United States heavy-duty truck market; and

· Building ANGH imposes significant added responsibilities on our management team and will divert their attention from other areas of our business.

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, and our ability to repay our debt.

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 natural gas truck purchasers are not satisfied with truck performance, additional heavy-duty truck engine manufacturers do not enter the market for natrual gas engines, or natural gas engines are not otherwise developed, produced and adopted in greater numbers, our ANGH investments and natural gas 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.

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 March 31, 2013, we had total cash and cash equivalents of $82.6 million, short-term investments of $38.0 million and $1.4 million in restricted cash for capital use. Our business plan calls for approximately $139.5 million in capital expenditures from April 1, 2013 through the end of 2013. 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 March 31, 2013, our future payments for IMW and Northstar totaled $12.4 million and $4.1 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.

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 notes, high yield debt, asset based loans, project finance debt, 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.

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We are required to make substantial payments to the holders of our convertible notes.

At March 31, 2013, we had an aggregate of $245.0 million of convertible notes outstanding (such convertible notes were issued in July 2011, August 2011, and July 2012). In addition, we have agreed to issue an additional $50.0 million of convertible notes in June 2013. All such convertible notes bear interest at the rate of 7.5% per annum. The $50.0 million outstanding principal amount of convertible notes we issued in July 2011 is due and payable in July 2018; the $145.0 million outstanding principal amount of convertible notes we issued in August 2011 is due and payable in August 2016; and the $50.0 million outstanding principal amount of convertible notes we issued in July 2012 is due and payable in July 2019. We may repay the convertible notes in common stock or cash. We expect our interest payment obligations under the convertible notes to be approximately $20.6 million for the year ending December 31, 2013 (such amount includes the interest that will be due on an additional $50.0 million of convertible notes we anticipate issuing in June 2013). In future periods, we may not have sufficient capital resources to enable us to fulfill our payment obligations to the holders of our convertible notes. If we are unable to make scheduled payments or comply with the other provisions of the agreements relating to the convertible notes, the holders of such convertible notes may be permitted under certain circumstances to accelerate the maturity of the convertible notes and exercise other remedies provided for in the notes and under applicable law. An acceleration of the maturity of the convertible notes that is not rescinded will have a material adverse effect on our company.

We may encounter difficulties building the GE Plants and such facilities may never be completed. If we commence construction of either GE Plant we will need to comply with significant obligations to GE.

Our ability to commence construction of the two LNG plants financed under the GE Credit Agreement (the “GE Plants”) will depend on a number of conditions, including the availability of sites upon which to construct the GE Plants and our ability to acquire title to, or leasehold interests in, such sites and the receipt of all governmental approvals necessary to design, develop, own, construct, install, operate and maintain the GE Plants. If we do not satisfy all of the conditions by December 31, 2014, GE’s obligation to fund the GE Plants will terminate. This may result in us not being able to satisfy our LNG supply needs, and may adversely affect us.

If we commence construction of either GE Plant, we may not be able to comply with all of our obligations to GE. For example, we may not complete one or both of the GE Plants within the required time period, or we may not make our required equity contributions to the plants. The GE Plants may cost more than we expect, and we may not be able to pay the additional cost. If the GE Plants are completed, they may not generate enough cash flow to pay our obligations to GE because they may not operate correctly or we may not be able to sell enough of the LNG the plants produce. If we do not fulfill our obligations, we may lose all of our investments in the GE plants, GE may take over ownership of the GE plants, and GE may sue us for damages.

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 may cause potential customers to delay or reject converting their fleets to run on natural gas. In that event, our sales of natural gas fuel and vehicles would be slowed and our business would suffer.

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

In the recent past, the price of natural gas has been volatile, and this volatility may continue. Increased natural gas prices affect the cost to us of natural gas and will adversely impact our operating margins in cases where we 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

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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 is influenced by government incentives and mandates for clean burning fuels and alternative fuel vehicles. The failure to pass new legislation with 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 and RNG 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 which promote the use of natural gas and RNG 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 2, would adversely affect our business and ability to sell RNG we produce at a profit. 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. Reduction in tax revenues associated with high unemployment rates or 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.

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 and RNG 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. 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 sell increasing amounts of CNG, LNG and RNG, which we may not be able to do. 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 product or service offerings acceptable.

We face increasing competition from oil and gas companies, 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 and their affiliates, industrial gas companies, station owners, fuel providers and other organizations have entered or are planning to enter the natural gas fuels market. For example, Shell Oil Products U.S. has publicized its plans to construct and operate a network of natural gas fueling stations at TravelCenters of America locations in the United States. In addition, ENN Group Co Ltd, one of China’s largest private companies, has announced plans to establish a network of natural gas fueling stations for trucks along U.S. highways, and expects to build 50 such stations in 2013. 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, and in December 2012, the California Public Utilities Commission approved a compression services tariff application by the Southern California Gas Company, allowing the utility to offer natural gas

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fueling infrastructure construction services that compete with our offerings. In addition, utilities in several states, including Michigan, Illinois, New Jersey, North Carolina and Georgia, have 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.

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 encounter challenges managing our growth, which 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, expand and improve our financial reporting and legal compliance systems, and 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.

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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 could 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.

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) expansion into foreign markets, (iii) the introduction of IMW’s compressor and related equipment manufacturing and servicing business, which is a new product line for us, (iv) achievement of appropriate internal controls over financial reporting and (v) 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.

A significant portion of the purchase price of IMW was allocated to intangibles, including goodwill, and a write-off of all or part of these intangibles, including 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 regarding new business, believed to be reasonable, but which are inherently uncertain. Pursuant to the applicable accounting standards, we initially allocated $126.4 million of the purchase price for IMW to intangibles, including goodwill. Our intangibles, including 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 intangibles, including goodwill, could adversely affect our results of operations.

The failure of one of our subsidiaries to comply with the terms of its bond financing agreements would impair our rights in our Dallas, Texas RNG production facility.

Dallas Clean Energy McCommas Bluff, LLC (“DCEMB”), in which we indirectly own a 70% interest and which owns and operates our Dallas, Texas RNG production facility, 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”) in connection with its issuance of certain Revenue Bonds (see note 12 of the condensed consolidated financial statements). 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 (as defined in the Bond Agreements) 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.

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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 17% of our revenues for the three months ended March 31, 2013 and approximately 30%, 21% and 33% of our annual revenues in 2010, 2011 and 2012, 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, which has and may continue to reduce or curtail their ability to fund natural gas fuel programs, purchase natural gas vehicles or provide public transportation and services, which would harm our business. Furthermore, in response to budget deficits, such governmental entities have and may continue to request or demand that we lower our price for CNG or LNG fuel.

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

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, LNG or RNG 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.

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Our ability to obtain LNG is constrained by fragmented and limited production and increasing competition for 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, if any such plants cannot produce LNG meeting applicable composition specifications and requirements, or if we or others do not build additional LNG liquefaction plants, our LNG supply will be restricted. If we are unable to supply enough LNG that satisfies applicable specifications (either from our own plants or by purchasing it from third parties) to meet customer demand, we may be liable to our customers for penalties and damages and may lose customers. Competition for LNG supply is escalating. For example, we increasingly compete to purchase LNG with third parties that use LNG to fuel equipment deployed in oil and gas production activities. 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.

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 America’s Natural Gas Highway. 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 sales 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 our futures contracts do not qualify for hedge accounting, our net income (loss) 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. At March 31, 2013, 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) in the future based on fluctuations in the market value of our futures contracts from quarter to quarter. We had no realized derivative gains or losses related to our natural gas futures contracts for the years ended December 31, 2010, 2011 and 2012 or for the three months ended March 31, 2013. 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 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.

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

Our operations entail inherent risks, including equipment defects, malfunctions and failures and natural disasters, which could result in uncontrollable flows of natural gas, fires, explosions and other damages. For example, operation of LNG pumps requires special training and protective equipment because of the extreme low temperatures of LNG. LNG tanker trailers have also in the past been, and may in the future be, involved in accidents that result in explosions, fires and other damage. Improper refueling of LNG vehicles can result in venting of methane gas, 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.

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

We lend 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) 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 March 31, 2013, we had $5.7 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, emissions certifications 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 corrective 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 operations, we often need facility permits or licenses to address storm water or wastewater discharges, waste handling, and air emissions. 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.

Our RNG business may not be successful.

We completed a new RNG production facility in Canton, Michigan in 2012 and we are developing a pipeline quality RNG project near 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 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 current conventional natural gas prices or to sell, at favorable prices, credits we may generate under federal or state laws, rules and regulations, including RIN and LCFS Credits. 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 current conventional natural gas prices or to sell RIN Credits or other credits we generate at favorable prices, our

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business and financial results may be materially and adversely affected. In addition, due to recent regulatory and legislative changes in California, our ability to sell RNG produced by projects outside of California to California power plants for use as a Renewable Portfolio Standard (“RPS”) compliant fuel is limited. If we cannot sell RNG we produce to California power plants for use as a RPS compliant fuel, we may not be able to obtain long-term, fixed 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 RIN Credits and other credits, or if our customers are not otherwise willing to pay a premium for RNG, we will be unable to generate profit and financial return from these investments, and our financial results could be materially and adversely affected.

We may experience difficulties producing RNG.

Our financial results and operations will be negatively impacted if we experience difficulties producing RNG. Our ability to produce RNG may be adversely affected by a number of factors beyond our control including limited availability or unfavorable composition of collected landfill gas, failure to obtain and renew necessary permits, landfill mismanagement, problems with our critical equipment, and adverse or severe weather conditions. In addition, we may seek to upgrade or expand our RNG facilities, which may result in plant shutdowns or cause delays that reduce the amount of RNG we produce.

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 $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, $11.3 million, $16.3 million, $41.7 million, and $3.9 million for the three months ended 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, June 30, 2012, September 30, 2012, December 31, 2012, and March 31, 2013, 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, receipt of fuel tax credits and other government incentives, construction cost overruns, down time at our facilities, 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, increasing competition, 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 March 31, 2013, there were 88,511,691 shares of our common stock outstanding, 11,994,610 shares underlying outstanding options, 1,545,000 shares underlying restricted stock units, 2,130,682 shares underlying outstanding Series I warrants (all of which were sold in our registered direct offering that closed in November 2008), 5,000,000 shares underlying a warrant we issued in November 2012 to GE, and an aggregate of 15,995,781 shares underlying the convertible notes we issued in July 2011, August 2011 and July 2012. 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 of 1933, as amended (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.

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Further, as of March 31, 2013, 18,139,720 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 March 31, 2013, 1,124,309 shares in the aggregate were subject to future sales by our named executive officers and directors under these selling plans.

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 March 31, 2013, T. Boone Pickens owned in the aggregate approximately 22.2% 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.

Our stock price may be volatile.

The market price of our common stock has experienced, and may continue to experience, volatility and could be subject to fluctuations in price in response to various factors, some of which are beyond our control. In addition to the factors discussed in this Item 1A, factors that may cause volatility in our stock price include:

· our actual or perceived ability to capture a substantial share of the anticipated growth in the market for natural gas as a vehicle fuel;

· successful implementation of our business plans, including our plan to build America’s Natural Gas Highway;

· the development, commercial availability and market adoption of natural gas as a vehicle fuel and engines that operate on natural gas, particularly natural gas engines that are well-suited for the heavy-duty trucking market, including the Cummins-Westport 11.9 liter engine;

· production, sourcing and supply of LNG and RNG;

· changes in the worldwide prices for natural gas and for traditional vehicle fuels, such as gasoline and diesel;

· actual or perceived fluctuations in our operating results;

· sales of our common stock by us or our stockholders;

· a decline in demand for our common stock;

· the potential for oil and gas companies, natural gas utilities and others to enter the natural gas fuel market;

· changes in our key personnel;

· competitive developments;

· investor perception of our industry or our prospects; and

· changes in general economic and market conditions.

In addition, the securities markets have from time to time experienced significant price and volume fluctuations that are unrelated to the operating performance of particular companies, and in such instances, have affected the market prices of those securities. These market fluctuations may also materially and adversely affect the market price of our common stock.

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.

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Item 5.—Other Information

On March 18, 2013, we entered a lease (“Lease”) with The Irvine Company, LLC (“Landlord”). Pursuant to the Lease, we agreed to lease approximately 68,000 square feet of office space in Newport Beach, CA (“Premises”) for use as our corporate headquarters. The Lease has a term of 96 months and calls for us to initially pay $141,452 in monthly basic rent. Such rent amount increases over time, so that in the last year of the Lease we will pay $196,537 in monthly basic rent. We expect to commence occupancy of the Premises during the third quarter of 2013. The foregoing description of the Lease is a summary of the terms of such agreement. The Lease is attached hereto as Exhibit 10.80.

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Item 6.—Exhibits

(a) Exhibits

10.80*		Lease Agreement dated March 18, 2013 between the Registrant and The Irvine Compnay, LLC.

10.81*		First Amendment to Lease Agreement dated April 17, 2013 between the Registrant and The Irvine Company, LLC.

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 March 31, 2013, formatted in XBRL (eXtensible Business Reporting Language):

		(i) Condensed Consolidated Balance Sheets at December 31, 2012 and March 31, 2013;
		(ii) Condensed Consolidated Statement of Operations for the Three Months Ended March 31, 2012 and 2013;
		(iii) Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2012 and 2013;
		(iv) Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2013; and
		(v) Notes to Condensed Consolidated Financial Statements.

* 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, are deemed not filed for purposes of Section 18 of the Exchange Act, and otherwise are not subject to liability under those sections.

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SIGNATURE

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

	CLEAN ENERGY FUELS CORP.


Date: May 8, 2013	By:	/s/ RICHARD R. WHEELER
		Richard R. Wheeler
		Chief Financial Officer (Principal financial officer and duly authorized to sign on behalf of the registrant)