Clean Energy Fuels Corp.
Clean Energy Fuels Corp. (Form: 10-Q, Received: 08/10/2009 16:15:02)

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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 June 30, 2009

Commission File Number: 001-33480

CLEAN ENERGY FUELS CORP.
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of incorporation)
  33-0968580
(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.  ý

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

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

Large accelerated filer  o   Accelerated filer  ý   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 ý

        As of August 5, 2009, there were 59,692,712 shares of the registrant's common stock, par value $0.0001 per share, issued and outstanding.


Table of Contents


CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES
INDEX

Table of Contents

PART I.—FINANCIAL INFORMATION

   

 

Item 1.—Financial Statements (Unaudited)

  3

 

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

  21

 

Item 3.—Quantitative and Qualitative Disclosures About Market Risk

  37

 

Item 4.—Controls and Procedures

  38

PART II.—OTHER INFORMATION

   

 

Item 1.—Legal Proceedings

  38

 

Item 1A.—Risk Factors

  39

 

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

  51

 

Item 3.—Defaults upon Senior Securities

  51

 

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

  51

 

Item 5.—Other Information

  52

 

Item 6.—Exhibits

  52

2


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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, 2008 and June 30, 2009 (Unaudited)

 
  December 31,
2008
  June 30,
2009
 

Assets

             

Current assets:

             
 

Cash and cash equivalents

  $ 36,284,431   $ 19,775,730  
 

Restricted cash

    2,500,000     2,500,000  
 

Accounts receivable, net of allowance for doubtful accounts of $657,734 and $739,478 as of December 31, 2008 and June 30, 2009, respectively

    10,530,638     10,825,961  
 

Other receivables

    12,995,507     13,349,580  
 

Inventory, net

    3,110,731     4,237,261  
 

Deposits on LNG trucks

    6,197,746     2,801,983  
 

Prepaid expenses and other current assets

    3,542,387     3,394,613  
           
   

Total current assets

    75,161,440     56,885,128  

Land, property and equipment, net

    160,593,665     166,403,562  

Capital lease receivables

    364,500     1,645,098  

Notes receivable and other long-term assets

    7,176,755     9,753,995  

Investments in other entities

    4,879,604     6,729,396  

Goodwill

    20,797,878     20,797,878  

Intangible assets, net of accumulated amortization

    21,400,558     25,781,822  
           
   

Total assets

  $ 290,374,400   $ 287,996,879  
           

Liabilities and Stockholders' Equity

             

Current liabilities:

             
 

Current portion of long-term debt and capital lease obligations

  $ 2,232,875   $ 2,870,373  
 

Accounts payable

    14,276,591     13,491,951  
 

Accrued liabilities

    10,253,454     9,408,505  
 

Deferred revenue

    1,060,582     1,048,510  
           
   

Total current liabilities

    27,823,502     26,819,339  

Long-term debt and capital lease obligations, less current portion

    22,850,927     24,529,247  

Other long-term liabilities

    2,297,446     17,854,528  
           
   

Total liabilities

    52,971,875     69,203,114  

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 99,000,000 shares; issued and outstanding 50,238,212 shares and 50,255,212 shares at December 31, 2008 and June 30, 2009, respectively

    5,024     5,026  
 

Additional paid-in capital

    346,466,999     343,775,876  
 

Accumulated deficit

    (113,549,257 )   (129,032,223 )
 

Accumulated other comprehensive income

    853,837     929,844  
           
   

Total stockholders' equity of Clean Energy Fuels Corp. 

    233,776,603     215,678,523  
 

Noncontrolling interest in subsidiary

    3,625,922     3,115,242  
           
   

Total equity

    237,402,525     218,793,765  
           
   

Total liabilities and equity

  $ 290,374,400   $ 287,996,879  
           

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 and Six Months Ended

June 30, 2008 and 2009

(Unaudited)

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2008   2009   2008   2009  

Revenue:

                         
 

Product revenues

  $ 32,725,614   $ 24,827,576   $ 61,686,320   $ 53,209,857  
 

Service revenues

    1,087,367     3,042,455     2,074,018     4,908,318  
                   
   

Total revenues

    33,812,981     27,870,031     63,760,338     58,118,175  

Operating expenses:

                         
 

Cost of sales:

                         
   

Product cost of sales

    28,316,620     15,164,592     50,478,217     36,416,458  
   

Service cost of sales

    297,410     1,039,899     549,489     1,432,282  
 

Derivative (gain) loss

    (5,706,981 )   2,209,596     (5,706,981 )   2,386,363  
 

Selling, general and administrative

    12,139,133     11,591,451     23,726,851     23,157,440  
 

Depreciation and amortization

    2,184,019     4,123,037     4,247,440     7,740,090  
                   
   

Total operating expenses

    37,230,201     34,128,575     73,295,016     71,132,633  
                   
 

Operating loss

    (3,417,220 )   (6,258,544 )   (9,534,678 )   (13,014,458 )

Interest income (expense), net

    265,347     (59,538 )   1,104,563     (92,076 )

Other income (expense), net

    1,622     (146,341 )   39,978     (186,527 )

Income (loss) from equity method investments

    4,724     35,854     (140,322 )   52,418  
                   
   

Loss before income taxes

    (3,145,527 )   (6,428,569 )   (8,530,459 )   (13,240,643 )

Income tax expense

    (56,203 )   (72,963 )   (99,970 )   (140,850 )
                   
 

Net loss

    (3,201,730 )   (6,501,532 )   (8,630,429 )   (13,381,493 )

Loss of noncontrolling interest in net income

        124,766         510,680  
                   
 

Net loss attributable to Clean Energy Fuels Corp. 

  $ (3,201,730 ) $ (6,376,766 ) $ (8,630,429 ) $ (12,870,813 )
                   

Loss per share attributable to Clean Energy Fuels Corp.

                         
 

Basic

  $ (0.07 ) $ (0.13 ) $ (0.19 ) $ (0.26 )
                   
 

Diluted

  $ (0.07 ) $ (0.13 ) $ (0.19 ) $ (0.26 )
                   

Weighted average common shares outstanding

                         
 

Basic

    44,300,309     50,247,366     44,291,401     50,242,814  
                   
 

Diluted

    44,300,309     50,247,366     44,291,401     50,242,814  
                   

See accompanying notes to condensed consolidated financial statements.

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Clean Energy Fuels Corp.

Condensed Consolidated Statements of Cash Flows

For the Six Months Ended June 30, 2008 and 2009

(Unaudited)

 
  Six Months Ended
June 30,
 
 
  2008   2009  

Cash flows from operating activities:

             

Net loss

  $ (8,630,429 ) $ (13,381,493 )

Adjustments to reconcile net loss to net cash provided by (used in) operating activities:

             
 

Depreciation and amortization

    4,247,440     7,740,090  
 

Provision for doubtful accounts

    366,018     124,993  
 

Loss (gain) on disposal of assets

    (38,356 )   254,280  
 

Stock option expense

    5,098,331     7,020,144  
 

Derivative (gain) loss

    (5,706,981 )   2,386,363  
 

Common stock issued in exchange for services

    15,000      
 

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

             
   

Accounts and other receivables

    (5,413,292 )   (1,691,207 )
   

Inventory

    (292,524 )   109,936  
   

Return (deposits) on LNG trucks

    (1,840,000 )   3,395,813  
   

Margin deposits on futures contracts

    (1,236,000 )   (1,880,481 )
   

Capital lease receivables

    199,500     523,382  
   

Prepaid expenses and other assets

    (1,039,868 )   289,104  
   

Accounts payable

    2,186,084     1,636,953  
   

Accrued expenses and other

    (827,382 )   (946,326 )
           
     

Net cash provided by (used in) operating activities

    (12,912,459 )   5,581,551  
           

Cash flows from investing activities:

             
 

Purchases of property and equipment

    (36,719,601 )   (18,153,466 )
 

Proceeds from sale of property and equipment

    48,432     49,666  
 

Acquisition, net of cash acquired

        (5,645,250 )
 

Investments in other entities

        (2,023,007 )
 

Proceeds from sale of loans receivable

        1,315,667  
 

Purchases of short-term investments

    (43,430,041 )    
 

Maturity or sales of short-term investments

    47,501,532      
           
     

Net cash used in investing activities

    (32,599,678 )   (24,456,390 )
           

Cash flows from financing activities:

             
 

Proceeds from long-term debt

        3,059,570  
 

Repayment of capital lease obligations and long-term debt

    (30,969 )   (743,752 )
 

Proceeds from exercise of stock options

    133,643     50,320  
           
     

Net cash provided by financing activities

    102,674     2,366,138  
           
     

Net decrease in cash

    (45,409,463 )   (16,508,701 )

Cash, beginning of period

    67,937,602     36,284,431  
           

Cash, end of period

  $ 22,528,139   $ 19,775,730  
           

Supplemental disclosure of cash flow information:

             
 

Income taxes paid

  $ 116,567   $ 51,569  
 

Interest paid, net of $0 and $418,000 capitalized, respectively

    10,606     375,372  

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)

Note 1—General

        Nature of Business:     Clean Energy Fuels Corp. (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 public transit, refuse, airports and regional trucking. The Company operates, maintains or supplies approximately 185 natural gas fueling locations in Arizona, California, Colorado, District of Columbia, Georgia, Maryland, Massachusetts, Nevada, New Mexico, New York, Ohio, Oklahoma, Texas, Virginia, Washington and Wyoming within the United States, and in British Columbia and Ontario within Canada. The Company also generates revenue through operation and maintenance agreements with certain customers, through building and selling or leasing natural gas fueling stations to its customers, and through financing its customers' vehicle purchases. In April 2008, the Company opened its first compressed natural gas ("CNG") station in Lima, Peru through the Company's joint venture, Clean Energy del Peru. In August 2008, the Company acquired 70% of the outstanding membership interests of Dallas Clean Energy, LLC ("DCE"). DCE owns a facility that collects, processes and sells renewable biomethane collected from a landfill in Dallas, Texas.

        Basis of Presentation:     The accompanying interim unaudited condensed consolidated financial statements include the accounts of the Company and its subsidiaries, and, in the opinion of management, reflect all adjustments, which include only normal recurring adjustments, necessary to state fairly the Company's financial position, results of operations and cash flows for the three and six months ended June 30, 2008 and 2009. All intercompany accounts and transactions have been eliminated in consolidation. The three and six month periods ended June 30, 2008 and 2009 are not necessarily indicative of the results to be expected for the year ending December 31, 2009 or for any other interim period or for any future year.

        Certain information and disclosures normally included in the notes to consolidated financial statements have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (the "SEC"), but the resultant disclosures contained herein are in accordance with accounting principles generally accepted in the United States of America 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, 2008 that are included in the Company's Annual Report on Form 10-K filed with the SEC on March 16, 2009.

        The Company has evaluated its subsequent events through August 10, 2009.

Note 2—Acquisitions

Operating and Maintenance Contracts

        In May 2009, the Company acquired four compressed natural gas operations and maintenance services contracts for $5.6 million in cash subject to certain post-closing adjustments. The Company has completed a preliminary allocation of the purchase consideration to tangible and intangible assets acquired and liabilities assumed based upon estimates of fair value. Such allocation includes $5.1 million to the identifiable intangible assets related to the fair value of the acquired operations and maintenance services contracts and associated customer relationships, which are being amortized over their expected lives. The results of operations of the acquired contracts are included in the Company's consolidated financial statements from their acquisition dates forward, which are May 2009 for two of

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 2—Acquisitions (Continued)


the contracts and June 2009 for the remaining two contracts. The pro-forma effect of the acquisition is not material to the Company's results of operations for the six months ended June 30, 2009 and the year ended 2008.

Landfill Operation

        On August 15, 2008, the Company and Cambrian Energy McCommas Bluff LLC ("Cambrian") formed a joint venture to acquire all of the outstanding membership interests of Dallas Clean Energy, LLC ("DCE") which owns a facility that collects, processes and sells landfill gas at the McCommas Bluff landfill located in Dallas, Texas. This acquisition enables the Company to participate in the production of pipeline quality renewable biomethane which may be used as a vehicle fuel.

        The Company paid an aggregate of $19.6 million, including transaction costs, to acquire a 70% interest in DCE. Of the purchase price, $1.0 million was deposited into a third-party escrow as security for indemnification claims. The amount remaining in the escrow will be released to the sellers on August 15, 2009, except for amounts subject to pending indemnification claims, if any.

        Also as part of the transaction, the Company granted DCE's minority investor an exclusive, non-assignable option to purchase from the Company up to and including a 19% membership interest in DCE. The exercise price of the option is $368,000 for each 1%, up to $6,992,000 for the total 19%. The option may be exercised as a whole or in part (but only in 1% increments) during the ten-year period commencing on the date which the loan made by the Company to DCE has been repaid in full.

        The Company borrowed $18.0 million from PlainsCapital Bank ("PCB") to finance its acquisition of its membership interests in DCE. The Company also obtained a $12.0 million line of credit from PCB to finance capital improvements of the DCE processing facility pursuant to a loan made by the Company to DCE and to pay certain costs and expenses related to the acquisition and the PCB loan. As of June 30, 2009, the Company had borrowed $7.7 million under the line of credit (see note 10).

        The Company accounted for the acquisition in accordance with SFAS No. 141, Business Combinations. The Company has completed a preliminary allocation of the purchase price. Such allocation and amounts may change as management finalizes its analyses. The assets acquired and liabilities assumed were recorded at their estimated fair values at the acquisition date. The following table summarizes the preliminary allocation of the aggregate purchase price to the fair value of the assets acquired and liabilities assumed, net of Cambrian's minority interest, in the DCE acquisition:

Current assets

  $ 1,129,389  

Property, plant and equipment

    1,821,770  

Identifiable intangible assets

    21,810,986  
       
 

Total assets acquired

    24,762,145  
       

Current liabilities assumed

    (1,480,770 )

Non-controlling interest

    (3,730,751 )
       
 

Total purchase price

  $ 19,550,624  
       

        Management preliminarily allocated approximately $21.8 million to the identifiable intangible asset related to the fair value of DCE's landfill lease with the City of Dallas that was acquired with the

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 2—Acquisitions (Continued)


acquisition. The fair value of the identifiable intangible asset will be amortized on a straight-line basis over the remaining life of the lease, approximately 16.5 years at the acquisition date.

        The results of DCE's operations have been included in the Company's consolidated financial statements since August 15, 2008. The pro-forma effect of the acquisition is not material to the Company's results of operations for the years ended December 31, 2007 and 2008.

Note 3—Cash and Cash Equivalents

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

Note 4—Natural Gas Derivative Financial Instruments

        The Company, in an effort to manage its natural gas commodity price risk exposures related to certain contracts, utilizes derivative financial instruments. The Company, from time to time, enters into natural gas futures contracts that are over-the-counter swap transactions that convert its index-based gas supply arrangements to fixed-price arrangements. The Company accounts for its derivative instruments in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities , as amended ("SFAS 133"). SFAS 133 requires the recognition of all derivatives as either assets or liabilities in the consolidated balance sheet and the measurement of those instruments at fair value. Historically through June 30, 2008, the Company's derivative instruments have not qualified for hedge accounting under SFAS 133. On and after July 1, 2008, the Company entered into futures contracts that did qualify for hedge accounting. The Company's futures contracts at June 30, 2009 are being accounted for as cash flow hedges under SFAS 133 and are being used to mitigate the Company's exposure to changes in the price of natural gas and not for speculative purposes. At June 30, 2009, all of the Company's futures contracts qualified for hedge accounting.

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

        The Company marks to market its open futures positions at the end of each period and records the net unrealized gain or loss during the period in derivative (gains) losses in the consolidated statements of operations or in accumulated other comprehensive income in the condensed consolidated balance sheets in accordance with the provisions of SFAS 133. The Company recorded unrealized losses of approximately $35,000 in accumulated other comprehensive income for the six month period ended June 30, 2009 related to its futures contracts. The liability for the Company's futures contracts of approximately $689,000 at June 30, 2009 is included in accrued liabilities and other long-term liabilities on the Company's condensed consolidated balance sheet at June 30, 2009. The Company's ineffectiveness related to its futures contracts during the six month period ended June 30, 2009 was insignificant. For the six month period ended June 30, 2009, the Company recognized losses of

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 4—Natural Gas Derivative Financial Instruments (Continued)


approximately $1.1 million in cost of sales in the accompanying condensed consolidated statement of operations related to its futures contracts that did qualify for hedge accounting.

        The Company is required to make certain deposits on its futures contracts, should any exist. At June 30, 2009, the Company had $2.6 million of margin deposits related to its futures contracts covering approximately 35.2 million gallons of fuel, of which $668,000 related to contracts that expire in the next 12 months and were classified as current at June 30, 2009. The deposits are recorded in prepaid expenses and other current assets and notes receivable and other long-term assets in the accompanying condensed consolidated balance sheet as of June 30, 2009.

        The following table presents the notional amounts and weighted average fixed prices of the Company's natural gas futures contracts as of June 30, 2009:

 
  Gallons   Weighted
Average Price
 
July to December, 2009     6,600,000   $ 0.62  
2010     11,600,000     0.77  
2011     11,600,000     0.82  
2012     5,080,000     0.82  
January to May, 2013     300,000     0.81  

Note 5—Fixed Price and Price Cap Sales Contracts

        The Company enters into contracts with various customers, primarily municipalities, to sell LNG or CNG at fixed prices, or through December 31, 2006, at prices subject to a price cap. The contracts generally range from two to five years. The most significant cost component of LNG and CNG is the price of natural gas.

        As part of determining the fixed price or price cap in the contracts, the Company works with its customers to determine their future usage over the contract term. However, the Company's fixed price and price cap customers do not agree to purchase a minimum amount of volume or guarantee their volume of purchases. There is not an explicit volume in the contract as the Company agrees to sell its customers volumes on an "as needed" basis, also known as a "requirements contract." The volume required under these contracts varies each month, and is not subject to any minimum commitments. For U.S. generally accepted accounting purposes, there is not a "notional amount," which is one of the required conditions for a transaction to be a derivative pursuant to the guidance in SFAS 133.

        The Company's sales agreements that fix the price or cap the price of LNG or CNG that it sells to its customers are, for accounting purposes, firm commitments, and U.S. generally accepted accounting principles do not require or allow the Company to record a loss until the delivery of the gas and corresponding sale of the product occurs. When the Company enters into these fixed price or price cap contracts with its customers, the price is set based on the prevailing index price of natural gas at that time. However, the index price of natural gas constantly changes, and a difference between the fixed price of the natural gas included in the customer's contract price and the corresponding index price of natural gas typically develops after the Company enters into the sales contract (with the price of natural gas having historically increased). From time to time, the Company has also entered into natural gas futures contracts to offset economically the adverse impact of rising natural gas prices (see

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 5—Fixed Price and Price Cap Sales Contracts (Continued)


note 4), and prior to December 31, 2006, if the Company believed the price of natural gas would decline in the future, periodically sold such contracts.

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

Note 6—Other Receivables

        Other receivables at December 31, 2008 and June 30, 2009 consisted of the following:

 
  December 31,
2008
  June 30,
2009
 

Loans to customers to finance vehicle purchases

  $ 1,983,414   $ 1,226,710  

Capital lease receivables

    399,000     1,737,003  

Accrued billings

        1,175,786  

Advances to vehicle manufacturers

    4,510,386     4,672,433  

Fuel tax credits

    5,511,908     3,842,069  

Other

    590,799     695,579  
           

  $ 12,995,507   $ 13,349,580  
           

Note 7—Land, Property and Equipment

        Land, property and equipment at December 31, 2008 and June 30, 2009 are summarized as follows:

 
  December 31,
2008
  June 30,
2009
 

Land

  $ 472,616   $ 472,616  

LNG liquefaction plants

    88,366,069     90,995,440  

Station equipment

    57,994,315     76,043,436  

LNG tanker trailers

    11,863,681     11,859,608  

Other equipment

    11,533,656     12,625,291  

Construction in progress

    22,439,115     12,479,455  
           

    192,669,452     204,475,846  

Less accumulated depreciation

    (32,075,787 )   (38,072,284 )
           

  $ 160,593,665   $ 166,403,562  
           

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 8—Investments in Other Entities

        Through June 30, 2009, the Company invested approximately $6.4 million in The Vehicle Production Group LLC ("VPG"), a company that is developing a natural gas vehicle made in the United States for taxi and paratransit use. On July 16, 2009, the Company invested an additional $939,000 in VPG. The Company committed to fund up to $10.0 million in VPG from August 2008 through March 2010. $7.5 million is a firm commitment by the Company, and $2.5 million is contingent on VPG not being able to raise money on more-favorable terms than the funding from the original investor group. In addition, VPG may under certain circumstances make a capital call on investors which could require the Company to invest up to approximately $0.8 million in additional funds. The Company accounts for its investment in VPG under the cost method of accounting as the Company does not have the ability to exercise significant influence over VPG's operations.

        On August 27, 2008, a subsidiary of the Company converted outstanding commercial loans previously made to Bachman NGV, Inc. ("BAF"), a natural gas vehicle conversion company, into a secured convertible promissory note (the "Note") that is convertible into equity interests in BAF. The Note is convertible at the Company's option after August 27, 2009 and may be converted earlier upon an acquisition of BAF. As of June 30, 2009, the $3.8 million outstanding under the Note would convert into approximately 49% of the outstanding equity interests of BAF if fully converted. The Company may, at the Company's discretion, advance up to $2.2 million in additional funds to BAF under the Note. The Note bears interest at 5% per annum and is due August 30, 2010.

Note 9—Accrued Liabilities

        Accrued liabilities at December 31, 2008 and June 30, 2009 consisted of the following:

 
  December 31,
2008
  June 30,
2009
 

Salaries and wages

  $ 568,760   $ 1,867,975  

Accrued gas purchases

    777,086     1,113,618  

Accrued refund of tax credits

    3,606,000      

Obligation under derivative liability

    654,483     474,421  

Accrued property and other taxes

    1,705,469     2,269,420  

Accrued professional fees

    1,230,958     666,567  

Accrued employee benefits

    434,788     694,321  

Other

    1,275,910     2,322,183  
           

  $ 10,253,454   $ 9,408,505  
           

Note 10—Long-term Debt

        In conjunction with the Company's acquisition of its 70% interest in DCE (see note 2), on August 15, 2008, the Company entered into a Credit Agreement with PCB. The Company borrowed $18.0 million (the "Facility A Loan") to finance the acquisition of its membership interests in DCE. The Company also obtained a $12.0 million line of credit from PCB to finance capital improvements of the DCE processing facility and to pay certain costs and expenses related to the acquisition and the PCB loans (the "Facility B Loan"). As of June 30, 2009, the Company had borrowed $7.7 million under the Facility B Loan. The Company may request funds up to an additional approximately $4.3 million

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 10—Long-term Debt (Continued)


under the Facility B Loan through August 14, 2009. Interest accrues daily on the Facility A and B Loans at the greater of the prime rate of interest for the United States plus 0.50% per annum or 5.50% per annum. The Company paid a facility fee of $300,000 in connection with the Credit Agreement. As of June 30, 2009, the unamortized balance of the facility fee was $247,500. Amortization of the facility fee is recorded as additional interest expense in the consolidated statements of operations.

        The Facility A Loan is due in level payments of principal and interest based on a 14 year amortization period. Payments of principal and interest are due on the 15th of each month until August 15, 2013, at which time the remaining amount of the unpaid principal and interest on the Facility A Loan is due and payable.

        Interest on the unpaid principal balance of the Facility B Loans became due and payable quarterly commencing on September 30, 2008. The principal amount of the Facility B Loans became due and payable in annual payments commencing on August 1, 2009, and continuing each anniversary date thereafter, with each such payment being in an amount equal to the lesser of twenty percent of the aggregate principal amount of the Facility B Loan then outstanding or $2,800,000. On August 15, 2013, the remaining amount of unpaid principal and interest under the Facility B Loans is due and payable.

        The Credit Agreement requires the Company to comply with certain covenants. The Company may not incur indebtedness or liens except as permitted by the Credit Agreement, or declare or pay dividends. The Company must maintain, on a quarterly basis, minimum liquidity of not less than $6.0 million, accounts receivable balances, as defined, of not less than $8.0 million, consolidated net worth, as defined, of not less than $150.0 million, and a debt to equity ratio, as defined, of not more than 0.3 to 1. Beginning in the quarter ended June 30, 2009, the Company must also maintain a debt service ratio, as defined, of not less than 1.5 to 1 at each quarter end. Effective in the fourth quarter of 2008, the Company established a lock-box arrangement with PCB subject to the Credit Agreement. Funds from the Company's customers are remitted to the lock-box and then deposited to a PCB bank account. The remitted funds are not used to pay-down the balance of the credit agreement. However, if the Company defaults on the Credit Agreement, all of the obligations under the Credit Agreement will become immediately due and payable and all funds received in the Company's lock-box held by PCB will be applied to the balance due on the Facility A and B Loans. One of the events of default is the occurrence of a "material adverse change," which is a subjective acceleration clause. Based on the guidance in Emerging Issues Tax Force Issue No. 95-22 Balance Sheet Classification of Borrowings Outstanding under Revolving Credit Agreements That Include both a Subjective Acceleration Clause and a Lock-Box Arrangement (EITF No. 95-22), the Company has classified its debt pursuant to the Credit Agreement as short-term or long-term as appropriate and believes an event of default is more than remote but not more likely than not. One of the Company's bank covenants is a requirement to maintain accounts receivable balances from certain subsidiaries above $8.0 million at each quarter end during the term. To the extent natural gas prices fall, which a significant portion of the Company's revenues are derived from, or the Company's volumes decline, the Company could violate this covenant in the future. Beginning with the quarter ended June 30, 2009, the Company is required to maintain a debt service ratio, as defined, of not less than 1.5 to 1. To the extent the Company's operating results do not materialize as anticipated, the Company could violate this covenant in the future. In the event the Company would violate either of these covenants, it would seek a waiver from the bank. The

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 10—Long-term Debt (Continued)


Company is in compliance with the covenants as of June 30, 2009. The Credit Agreement is secured by the Company's interest in, and note receivable from, DCE (described below), certain of the Company's accounts receivable and inventory balances and 45 of the Company's LNG tanker trailers. The net book value of the collateral securing the PCB loans was approximately $45.0 million at June 30, 2009. The Company maintains $2.5 million in a payment reserve account at PCB. PCB may withdraw funds from the account to apply to the principal and interest payments due on Facility A and B Loans. Such amount is included as restricted cash in the Company's consolidated balance sheet at June 30, 2009.

        As part of the transaction, the Company also entered into a Loan Agreement with DCE (the "DCE Loan") to provide secured financing of up to $14.0 million to DCE for future capital expenditures or other uses as agreed to by the Company in its sole discretion. As of August 7, 2009 we have approximately $4.4 million in debt financing outstanding under the DCE Loan. Interest on the unpaid balance accrues at a rate of 12% per annum and became payable quarterly beginning on September 30, 2008. The principal amount of the loan is due and payable in annual payments commencing on August 1, 2009, and continuing each anniversary date thereafter, with each such payment being in an amount equal to the lesser of the aggregate principal amount of the DCE Loan then outstanding or $2,800,000. On August 1, 2013, the entire amount of unpaid principal and interest under the DCE Loan is due and payable. The principal and accrued interest balances as well as any interest income related to the DCE Loan are eliminated in the consolidated financial statements of the Company. Any event of default by DCE on the DCE Loan results in a cross-default of the Company's Credit Agreement with PCB. Events of default include failure to make payments when due, DCE's failure to perform under the provisions of its landfill lease with the City of Dallas, DCE's violation of a covenant under its operating agreement and other standard events of default.

        Principal payments under the Facility A Loan and the Facility B Loan at June 30, 2009 are as follows:

 
  Facility A Loan   Facility B Loan   Total  

2009

  $ 446,126   $ 1,549,341   $ 1,995,467  

2010

    931,536     1,239,474     2,171,010  

2011

    984,831     991,578     1,976,409  

2012

    1,038,825     793,263     1,832,088  

2013

    13,875,000     3,173,050     17,048,050  
               

Total

  $ 17,276,318   $ 7,746,706   $ 25,023,024  
               

Note 11—Correction of Immaterial Error

        Subsequent to the year ended December 31, 2008, the Company identified an error in the number of gallons it used to claim its Volumetric Excise Tax Credit ("VETC") refund. Due to this error, the Company's revenues were understated in 2007 and overstated in 2008.

        The Company assessed the materiality of this error for each quarterly and annual period in accordance with Staff Accounting Bulletin No. 99, Materiality, and determined that the error was immaterial to previously reported amounts contained in its periodic reports. Accordingly, the Company has revised its consolidated balance sheet as of December 31, 2008 and it intends to revise its

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 11—Correction of Immaterial Error (Continued)


consolidated financial statements for certain quarterly and annual periods through subsequent periodic filings. For quarters prior to June 30, 2008, the Company's financial statements have not been revised as the net amount of the error is insignificant. The effect of recording this immaterial correction in the statements of operations for the year ended December 31, 2008, the balance sheet as of December 31, 2008, and for the fiscal 2008 quarterly periods to be reported in subsequent periodic filings are as follows:

 
  For the Quarter Ended
June 30, 2008
  For the Quarter Ended
September 30, 2008
  For the Quarter Ended
December 31, 2008
  For the Year Ended
December 31, 2008
 
(in thousands)
  As Reported   As Revised   As Reported   As Revised   As Reported   As Revised   As Reported   As Revised  

Total revenues

  $ 34,602   $ 33,813   $ 35,274   $ 33,819   $ 29,650   $ 28,288   $ 129,473   $ 125,867  

Operating loss

    (2,628 )   (3,417 )   (10,594 )   (12,049 )   (22,606 )   (23,968 )   (41,945 )   (45,551 )

Net loss

    (2,413 )   (3,202 )   (10,637 )   (12,092 )   (22,378 )   (23,740 )   (40,857 )   (44,463 )

Accrued liabilities

    4,654     5,443     7,252     9,496     6,647     10,253     6,647     10,253  

Accumulated deficit

    (76,928 )   (77,717 )   (87,565 )   (89,809 )   (109,943 )   (113,549 )   (109,943 )   (113,549 )

Total stockholders' equity

    228,283     227,494     224,173     221,929     237,383     233,777     237,383     233,777  

Note 12—Earnings Per Share

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

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2008   2009   2008   2009  

Basic and diluted:

                         
 

Weighted average number of common shares outstanding

    44,300,309     50,247,366     44,291,401     50,242,814  

        Certain securities were excluded from the diluted earnings per share calculations at June 30, 2008 and 2009, respectively, as the inclusion of the securities would be anti-dilutive to the calculation. The amounts outstanding as of June 30, 2008 and 2009 for these instruments are as follows:

 
  June 30,  
 
  2008   2009  

Options

    6,741,654     9,259,052  

Warrants

    15,000,000     18,314,394  

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 13—Comprehensive Income (Loss)

        The following table presents the Company's comprehensive loss for the six months ended June 30, 2008 and 2009:

 
  Six Months Ended
June 30,
 
 
  2008   2009  

Net loss

  $ (8,630,429 ) $ (13,381,493 )

Unrealized gain on short-term investments

    60,927      

Derivative unrealized losses

        (34,624 )

Foreign currency translation adjustments

    (116,017 )   110,631  
           

Comprehensive loss

    (8,685,519 )   (13,305,486 )

Comprehensive loss attributable to noncontrolling interest

        510,680  
           

Comprehensive loss attributable to Clean Energy Fuels Corp. 

  $ (8,685,519 ) $ (12,794,806 )
           

Note 14—Stock-Based Compensation

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

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2008   2009   2008   2009  

Stock options:

                         

Stock-based compensation expense

  $ 2,599,895   $ 3,506,322   $ 5,098,331   $ 7,020,144  

Income tax benefit

                 
                   
 

Stock-based compensation expense, net of tax

  $ 2,599,895   $ 3,506,322   $ 5,098,331   $ 7,020,144  
                   

Stock Options

        The following table summarizes the Company's stock option activity during the six months ended June 30, 2009:

 
  Number of
Shares
  Weighted-Average
Exercise Price
 

Outstanding at December 31, 2008

    8,234,467   $ 9.14  

Granted

    1,087,913     6.57  

Exercised

    (17,000 )   2.96  

Cancelled/Forfeited

    (46,328 )   9.96  
             

Outstanding at June 30, 2009

    9,259,052     8.84  
             

Exercisable at June 30, 2009

    4,577,143     7.90  
             

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 14—Stock-Based Compensation (Continued)

        The fair value of each option is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants in 2009:

 
  Six Months Ended
June 30, 2009
 

Dividend yield

    0.00 %

Expected volatility

    70.22 %

Risk-free interest rate

    2.00 %

Expected life in years

    6.00  

        Based on these assumptions, the weighted average grant date fair value of options granted during the six months ended June 30, 2009 was $4.16.

Note 15—Use of Estimates

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

Note 16—Environmental Matters, Litigation, Claims, Commitments and Contingencies

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

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

Note 17—Income Taxes

        FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109" (FIN 48), requires that the Company recognize the impact of a tax position in its financial statements if the position is more likely than not of being sustained by the taxing

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 17—Income Taxes (Continued)


authority upon examination, based on the technical merits of the position. FIN 48 requires the Company to accrue interest based on the difference between the tax position recognized in the financial statements and the amount claimed on the return. The net interest incurred was immaterial for the six months ended June 30, 2008 and 2009. FIN 48 further requires that penalties be accrued if the tax position does not meet the minimum statutory threshold to avoid penalties. No penalties have been accrued by the Company. The Company's unrecognized tax benefits as of June 30, 2009 are unchanged from December 31, 2008. It is anticipated that the Company's liability for uncertain tax positions will be reduced by as much as $319,000 during the year as a result of the settlement of tax positions with various tax authorities.

        The Company is subject to taxation in the United States and various states and foreign jurisdictions. The Company's tax years for 2003 through 2007 are subject to examination by various tax authorities. The Company is no longer subject to U.S. examination for years before 2005, and state examinations for years before 2004. The Company is currently under audit by the Internal Revenue Service for tax years 2005 through 2007.

Note 18—Fair Value Measurements

        On January 1, 2008, the Company adopted the applicable provisions of SFAS No. 157, Fair Value Measurements ("SFAS 157"), which defines fair value, establishes a framework for measuring fair value and enhances disclosures about fair value measurements related to financial instruments. In December 2007, the FASB provided a one-year deferral of SFAS 157 for non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value on a recurring basis, at least annually. Accordingly, the Company adopted SFAS 157 for non-financial assets and non-financial liabilities on January 1, 2009.

        During the six months ended June 30, 2009, the Company's financial instruments consisted of natural gas futures contracts, debt instruments, and its Series I warrants. The Company uses quoted forward price curves, discounted to reflect the time value of money, to value its natural gas futures contracts. The Company uses a Monte Carlo simulation model to value the Series I warrants, which requires the Company to make estimates regarding risk-free interest rates, the volatility of its stock price, and its anticipated dividend yield. The Company's futures contracts are recorded in accrued liabilities and other long-term liabilities and the Series I warrants are recorded in other long-term liabilities in the accompanying condensed consolidated balance sheet at June 30, 2009. The fair market value of the Company's debt instruments approximated their carrying values at June 30, 2009.

        The following table reflects the fair value as defined by SFAS 157, of the Company's natural gas futures contracts and the Series I warrants at June 30, 2009:

 
  Balance at
June 30,
2009
  Quoted Prices
In Active Markets
for Identical Items
(Level 1)
  Significant Other
Observable
Inputs
(Level 2)
  Significant
Unobservable
Inputs
(Level 3)
 

Natural gas futures contracts obligation

  $ 689,108   $   $ 689,108   $  

Series I warrants

  $ 14,760,101   $   $ 14,760,101   $  

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

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

        In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141(R), Business Combinations ("SFAS 141(R)"). SFAS 141(R) provides new accounting guidance and disclosure requirements for business combinations. SFAS 141(R) is effective for business combinations which occur beginning in 2009. The adoption of SFAS 141(R) did not have a material impact on the Company's financial statements.

        In December 2007, the FASB issued Statement of Financial Accounting Standard No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51 ("SFAS 160"). SFAS 160 requires presentation of non-controlling interests in consolidated subsidiaries separately within equity in the consolidated statements of financial position as well as the separate presentation within the consolidated statements of operations and comprehensive income (loss) attributable to the parent and noncontrolling interest. Accounting for changes in a parent's ownership interest, will generally be at fair value and if the parent retains control or significant influence of the subsidiary, any adjustments will be made through equity, while transactions where control changes occur will be accounted for through earnings. SFAS 160 was effective for the Company on January 1, 2009. As a result of adopting SFAS 160, the Company reclassified the minority interest of DCE to the stockholders' equity section of the consolidated balance sheet. References to minority interest in previous financial statements are now reflected as noncontrolling interest. The adoption of this statement did not have a material impact on the Company's consolidated financial position or results of operations.

        In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, "Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133" ("SFAS 161"). SFAS 161 amends and expands the disclosure requirements of FASB Statement No. 133 (SFAS 133), requiring enhanced disclosures about the Company's derivative and hedging activities. The Company is required to provide enhanced disclosures about (a) how and why it uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect the Company's financial position, results of operations, and cash flows. The Company adopted this statement as of January 1, 2009 and the adoption did not have a material impact on its consolidated financial statements.

        In April 2008, the FASB issued FASB Staff Position No. FAS 142-3, Determination of the Useful Life of Intangible Assets ("FSP FAS 142-3"). FSP FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, Goodwill and Other Intangible Assets. More specifically, FSP FAS 142-3 removes the requirement under paragraph 11 of SFAS 142 to consider whether an intangible asset can be renewed without substantial cost or material modifications to the existing terms and conditions and instead, requires an entity to consider its own historical experience in renewing similar arrangements. FSP FAS 142-3 also requires expanded disclosure related to the determination of intangible asset useful lives. FSP FAS 142-3 was effective for the Company on January 1, 2009. Adoption of this statement did not have a material impact on the Company's consolidated financial statements.

        In June 2008, the Emerging Issues Task Force (the "EITF") reached a consensus in EITF No. 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity's Own Stock

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 19—Recently Adopted Accounting Changes and Recently Issued Accounting Standards (Continued)


(EITF No. 07-5). The EITF concluded, among other things, that contingent and other adjustment features in equity-linked financial instruments are consistent with equity indexation if they are based on variables that would be inputs to a "plain vanilla" option or forward pricing model and they do not increase the contract's exposure to those variables. The Company's Series I warrants issued on October 28, 2008 are linked to the Company's own equity shares; however, the investor has protective pricing features commonly referred to as " down-round" protection, whereby the conversion price potentially resets if the common stock price of the Company declines after issuance. As a result of this guidance, effective January 1, 2009, the Company accounts for the Series I warrants as a derivative under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities . As a result of adopting EITF No. 07-5, the Company recorded a cumulative-effect adjustment of approximately $2.6 million to opening retained earnings and reclassed approximately $9.8 million from additional paid-in capital to long-term liabilities on the date of adoption, January 1, 2009. During the second quarter of 2009, the Company recorded a charge of $2.4 million related to valuing the Series I warrants.

        In May 2009, the FASB issued Statement of Financial Accounting Standards No. 165, Subsequent Events , ("SFAS 165") which establishes general standards of accounting for and disclosures of events that occur after the balance sheet date, but before the financial statements are issued or are available to be issued. SFAS 165 requires the disclosure of the date through which an entity has evaluated subsequent events, and is effective for interim and annual reporting periods ending after June 15, 2009. The Company adopted the new disclosure requirements on April 1, 2009 and its adoption did not have a material impact on the Company's consolidated financial statements.

        On June 30, 2009, the FASB issued FSP SFAS 107-1, Interim Disclosures about Fair Value of Financial Instruments . FSP 107-1, which amends SFAS No. 107, Disclosures about Fair Value of Financial Instruments , requires publicly-traded companies, as defined in APB Opinion No. 28, Interim Financial Reporting , to provide disclosures on the fair value of financial instruments in interim financial statements. The Company adopted the new disclosure requirements on April 1, 2009 and its adoption did not have a material impact on the Company's consolidated financial statements.

        In April 2009, the FASB issued FSP SFAS 157-4, "Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly," which provides additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for the asset or liability have significantly decreased. This FSP re-emphasizes that regardless of market conditions the fair value measurement is an exit price concept as defined in SFAS No. 157. This FSP clarifies and includes additional factors to consider in determining whether there has been a significant decrease in market activity for an asset or liability and provides additional clarification on estimating fair value when the market activity for an asset or liability has declined significantly. The scope of this FSP does not include assets and liabilities measured under Level 1 inputs. The Company adopted FSP SFAS 157-4 on April 1, 2009 and its adoption did not have a material impact on the Company's consolidated financial statements.

        On July 1, 2009, the FASB's Accounting Standards Codification , ("Codification") was released. The Codification will become the source of authoritative U.S. generally accepted accounting principles ("GAAP") recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 19—Recently Adopted Accounting Changes and Recently Issued Accounting Standards (Continued)


releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of this Statement, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in the Codification will become nonauthoritative. This Statement is effective for the Company's consolidated financial statements issued for interim and annual periods ending after September 15, 2009. The Company does not expect transition to the Codification will have a material impact on the Company's consolidated financial statements.

Note 20—Subsequent Events

        On July 1, 2009, the Company closed a follow-on public offering of 9,430,000 shares of common stock at a price of $8.30 per share. The aggregate amount of common shares sold reflects the exercise in full by the underwriters of their option to purchase 1,230,000 additional shares of the Company's common stock to cover over-allotments. The Company received aggregate net proceeds of approximately $73.2 million, after deducting underwriting discounts and commissions and estimated offering expenses payable by the Company.

        As a result of the follow-on public offering, the exercise price of the Company's Series I Warrants issued on October 28, 2008 was adjusted to $12.68 per share from $13.50 per share per the terms of the Series I warrant agreements.

Note 21—Volumetric Excise Tax Credit (VETC)

        The Company records its VETC credits as revenue in its condensed consolidated statements of operations as the credits are fully refundable and do not need to offset income tax liabilities to be received. VETC revenues for the six month periods ended June 30, 2008 and 2009 were approximately $9.1 million and $8.1 million, respectively.

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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, 2008 contained in our 2008 Annual Report, as well as the consolidated financial statements and notes contained therein.

Cautionary Statement Regarding Forward Looking Statements

         This MD&A and other sections of this report contain forward looking statements. We make forward-looking statements, as defined by the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995, and in some cases, you can identify these statements by forward-looking words such as "if," "shall," "may," "might," "will likely result," "should," "expect," "plan," "anticipate," "believe," "estimate," "project," "intend," "goal," "objective," "predict," "potential" or "continue," or the negative of these terms and other comparable terminology. These forward-looking statements, which are based on various underlying assumptions and expectations and are subject to risks, uncertainties and other unknown factors, may include projections of our future financial performance based on our growth strategies and anticipated trends in our business. These statements are only predictions based on our current expectations and projections about future events that we believe to be reasonable. There are important factors that could cause our actual results, level of activity, performance or achievements to differ materially from the historical or future results, level of activity, performance or achievements expressed or implied by such forward-looking statements. These factors include, but are not limited to, those discussed under the caption "Risk Factors" in this report and in our 2008 Annual Report. In preparing this MD&A, we presume that readers have access to and have read the MD&A in our 2008 Annual Report pursuant to Instruction 2 to paragraph (b) of Item 303 of Regulation S-K. We undertake no duty to update any of these forward-looking statements after the date of filing of this report to conform such forward-looking statements to actual results or revised expectations, except as otherwise required by law.

        We provide natural gas solutions for vehicle fleets primarily in the United States and Canada. Our primary business activity is selling CNG and LNG vehicle fuel to our customers. We also build, operate and maintain fueling stations, and help our customers acquire and finance natural gas vehicles and obtain local, state and federal clean air incentives. Our customers include fleet operators in a variety of markets, such as public transit, refuse hauling, airports, taxis and regional trucking. In April 2008, we opened our first compressed natural gas station in Lima, Peru, through our joint venture, Clean Energy del Peru. In August 2008, we acquired 70% of the outstanding membership interest of Dallas Clean Energy, LLC ("DCE"). DCE owns a facility that collects, processes and sells renewable biomethane collected from a landfill in Dallas, Texas.

    Overview

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

        Sources of revenue.     We generate the majority of our revenue from selling CNG and LNG and providing operations and maintenance services to our customers. The balance of our revenue is provided by designing and constructing natural gas fueling stations, financing our customers' natural gas vehicle purchases and sales of pipeline quality biomethane produced by our DCE joint venture.

        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 directly

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sell the CNG or LNG, plus (iii) our proportionate share of the gasoline gallon equivalents sold as CNG by our joint venture in Peru, plus (iv) our proportionate share of the gasoline gallon equivalents of biomethane produced and sold as pipeline quality natural gas by DCE); (2) our revenue; and (3) net income (loss). The following table, which you should read in conjunction with our condensed consolidated financial statements and notes contained elsewhere in this report, presents our key operating data for the years ended December 31, 2006, 2007 and 2008 and for the three and six months ended June 30, 2008 and 2009:

Gasoline gallon equivalents
delivered (in millions)
  Year Ended
December 31,
2006
  Year Ended
December 31,
2007
  Year Ended
December 31,
2008
  Three Months
Ended
June 30,
2008
  Six Months
Ended
June 30,
2008
  Three Months
Ended
June 30,
2009
  Six Months
Ended
June 30,
2009
 

CNG

    41.9     48.0     47.6     11.8     23.4     16.3     28.4  

Biomethane

            2.0             1.5     2.4  

LNG

    26.5     27.3     23.9     6.7     12.7     5.9     11.2  
                               

Total

    68.4     75.3     73.5     18.5     36.1     23.7     42.0  

 

Operating data
   
   
   
   
   
   
   
 

Revenue

  $ 91,547,316   $ 117,716,233   $ 125,866,533   $ 33,812,981   $ 63,760,338   $ 27,870,031   $ 58,118,175  

Net loss

    (77,500,741 )   (8,894,362 )   (44,462,574 )   (3,201,730 )   (8,630,429 )   (6,376,766 )   (12,870,813 )

        Key trends in 2006, 2007, and 2008 and the first six months of 2009.     Vehicle fleet demand for natural gas fuels increased during the three year and six-month period ended June 30, 2009. We believe this growth in demand was attributable primarily to the rising prices of gasoline and diesel relative to CNG and LNG during this period and increasingly stringent environmental regulations affecting vehicle fleets. We capitalized on this growing demand by securing new fleet customers in a variety of markets, including public transit, refuse hauling, airports, taxis and regional trucking.

        The number of fueling stations we served grew from 147 at December 31, 2004 to 185 at June 30, 2009 (a 25.9% increase). The amount of CNG and LNG gasoline gallon equivalents we delivered from 2006 to 2008 increased by 7.5%. The increase in gasoline gallon equivalents delivered, together with higher prices we charged our customers due to higher natural gas prices, contributed to increased revenues from 2006 through the end of 2008. During the first six months of 2009, our revenues declined as compared to the first six months of 2008 primarily due to lower natural gas prices. Our cost of sales also increased from 2006 through the end of 2008, which was attributable primarily to the increased costs related to delivering more CNG and LNG to our customers and the increased price of natural gas. Our cost of sales decreased during the first six months of 2009 as compared to the first six months of 2008 primarily due to lower natural gas prices.

        Recent developments.     On July 1, 2009, we closed a follow-on public offering of 9,430,000 shares of common stock at a price of $8.30 per share. The aggregate amount of common shares sold reflects the exercise in full by the underwriters of their option to purchase 1,230,000 additional shares of our common stock to cover over-allotments. We received aggregate net proceeds of approximately $73.2 million, after deducting underwriting discounts and commissions and estimated offering expenses.

        Anticipated future trends.     Despite the recent volatility and decline in energy prices, we anticipate that, over the long term, the prices for gasoline and diesel will continue to be higher than the price of natural gas as a vehicle fuel, and more stringent emissions requirements will continue to make natural gas vehicles an attractive alternative to traditional gasoline and diesel powered vehicles. Our belief that natural gas will continue, over the long term, to be a cheaper vehicle fuel than gasoline or diesel is based in part on the growth in U.S. natural gas production. A 2008 Navigant Consulting, Inc. study indicates that as a result of new unconventional gas shale discoveries from 22 basins in the U.S., maximum estimates of total recoverable domestic reserves from producers have increased to equal 118 years of U.S. production at 2007 producing rates. The study indicated a mean level of reserves

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equal to 88 years of supply at 2007 production levels. Indications were that shale gas production growth from only the major six shale plays, plus the Marcellus shale, could become 27 billion cubic feet per day and as high as 39 billion cubic feet per day by 2015. Navigant has also indicated that development of the shale resources base has resulted in a substantial current surplus of gas supply compared to demand of as much as 11 billion cubic feet per day. These current surplus levels are 18% of annual average historical U.S. consumption levels of approximately 20 Tcf per year making available gas supply to meet all existing markets and to meet new market requirements. Analysts believe that there is a significant worldwide supply of natural gas relative to crude oil as well. According to the 2008 BP Statistical Review of World Energy, on a global basis, the ratio of proven natural gas reserves to 2007 natural gas production was 45% greater than the ratio of proven crude oil reserves to 2007 crude oil production. This analysis suggests significantly greater longer term availability of natural gas than crude oil based on current consumption.

        We believe there will be significant growth in the consumption of natural gas as a vehicle fuel among vehicle fleets, and our goal is to capitalize on this trend and enhance our leadership position as this market expands. We have built natural gas fueling stations, and plan to build additional natural gas fueling stations, that will provide LNG to fleet vehicles at the Ports of Los Angeles and Long Beach. We also anticipate expanding our sales of CNG and LNG in the other markets in which we operate, including public transit, regional trucking, refuse hauling and airports. 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 as well as the logistics of delivering more CNG and LNG to our customers. 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.

        The disruption in the capital markets that began during 2008 and has continued into 2009 has made it more difficult for new customers to finance or invest in natural gas vehicle acquisitions or natural gas fueling stations. Continuing economic contraction and reduced economic activity may reduce our opportunities to attract new fleet customers. Many governmental entities, which during 2006 through 2008 represented approximately two-thirds of our revenues, are experiencing significant budget deficits as a result of the economic recession and have been and may continue to be unable to invest in new natural gas vehicles for their transit or refuse fleets or may be compelled to reduce public transportation and services, which would negatively affect our business.

        Sources of liquidity and anticipated capital expenditures.     In May 2007, we completed our initial public offering of 10,000,000 shares of common stock at a public offering price of $12.00 per share. Net cash proceeds from the initial public offering were approximately $108.5 million, after deducting underwriting discounts, commissions and offering expenses. Historically, our principal sources of liquidity have been cash provided by operations, capital contributions from our stockholders, our cash and cash equivalents and, during the third and fourth quarters of fiscal 2006, a revolving line of credit with Boone Pickens, a director and our largest stockholder. The line of credit was used to fund margin requirements on certain derivative contracts and was terminated in December 2006. In connection with our acquisition of 70% of the membership interests in DCE, we entered into a credit agreement on August 15, 2008 with PCB. We borrowed $18.0 million to finance the acquisition and entered into a $12.0 million line of credit from PCB to provide capital to DCE, primarily for capital expenditures, and to pay certain costs and expenses of the acquisition and the loans. As of August 7, 2009, approximately $4.3 million is available under the line of credit from PCB to provide further capital to DCE, however, we may only draw down on the line of credit through August 14, 2009. On September 24, 2008, we sold 319,488 shares of our common stock at a purchase price of $15.65 per share to Boone Pickens Interests, Ltd. for proceeds of approximately $5.0 million. On November 3, 2008, we sold 4,419,192 shares of common stock and warrants exercisable for common stock to third-party investors and

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received net proceeds of approximately $32.5 million. On July 1, 2009, we sold 9,430,000 shares of common stock to third-party investors and received net proceeds of $73.2 million.

        Our current business plan calls for approximately $14.9 million in additional capital expenditures from July 1, 2009 through the end of 2009, primarily related to construction of new fueling stations. In addition, we anticipate that during the remainder of 2009 we will provide approximately $0.3 million for financing natural gas vehicle purchases by our customers and up to $2.5 million in funding that we may be required to provide to the Vehicle Production Group, LLC, a company that is developing CNG paratransit vehicles and taxis. We anticipate that we will fund any capital expenditures of DCE during 2009 through our available cash reserves or our line of credit from PCB, if we fund such capital expenditures prior to August 14, 2009. We may also elect to invest additional amounts that are not budgeted for in our 2009 business plan in expansion of our California LNG plant, station construction for new or existing customers that are not currently under contract or for acquisitions or investments in companies or assets in the natural gas and biomethane fueling infrastructure, services and production industries. We intend to fund our principal liquidity requirements, other than our loan to DCE, through cash and cash equivalents and cash provided by operations. For more information, see "Liquidity and Capital Resources" below.

        Volatility in operating results related to futures contracts.     Historically, we have purchased futures contracts from time to time to help mitigate our exposure to natural gas price fluctuations in current periods and in future periods. Prior to 2008, our futures contracts did not qualify for hedge accounting under SFAS No. 133, and in 2008, some of our contracts qualified for hedge accounting under SFAS No. 133 and some did not. In 2009, all of our futures contracts did qualify for hedge accounting under SFAS 133. Gains and losses related to the futures contracts that did not qualify for hedge accounting, which appear in the line item derivative (gains) losses in our condensed consolidated financial statements, have materially impacted our results of operations in recent periods. For the years ended December 31, 2006, 2007 and 2008, derivative (gains) losses associated with futures contracts were $78,994,947, $0 and $611,175, respectively. For this reason and others, we caution investors that our past operating results may not be indicative of future results. For more information, please read "Volatility of Earnings and Cash Flows" and "Risk Management Activities" below.

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

Operations

        We generate revenues principally by selling CNG and LNG and providing operations and maintenance services to our vehicle fleet customers. For the six months ended June 30, 2009, CNG and biomethane (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. Substantially all of our operating and maintenance revenues are generated from CNG stations, as owners of LNG stations tend to operate and maintain their own stations. Substantially all of our station sale and leasing revenues have been generated from CNG stations. In 2006, we began providing vehicle finance services to our customers.

CNG Sales

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

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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 sell a small amount of CNG under fixed-price contracts and also provide price caps to certain customers on their index-plus pricing arrangement. Effective January 1, 2007, we ceased offering price-cap contracts to our customers, but we will continue to perform our obligations under price-cap contracts we entered into before January 1, 2007. We will continue to offer fixed price contracts as appropriate and consistent with our natural gas hedging policy that was revised in May 2008. Our fleet customers typically are billed monthly based on the volume of CNG sold at a station. The remainder of our CNG sales are on a per fill-up basis at prices we set at the pump based on prevailing market conditions. These customers typically pay using a credit card at the station. In April 2008, we opened our first CNG station in Lima, Peru through our joint venture Clean Energy del Peru.

LNG Sales

        We sell substantially all of our LNG to fleet customers, who typically own and operate their fueling stations. We also sell a small volume of LNG to customers for non-vehicle use. We procure LNG from third-party producers and also produce LNG at our liquefaction plants in Texas and California. For LNG that we purchase from third-parties, we typically enter into "take or pay" contracts that require us to purchase minimum volumes of LNG at index-based rates. We deliver LNG via our fleet of 58 tanker trailers to fueling stations, where it is stored and dispensed in liquid form into vehicles. We sell LNG principally through supply contracts that are priced on either a fixed-price or index-plus basis. LNG sales revenues based on an index-plus methodology increase or decrease as a result of an increase or decrease in the price of natural gas. We also provided price caps to certain customers on the index component of their index-plus pricing arrangement for certain contracts we entered into on or prior to December 31, 2006. Effective January 1, 2007, we ceased offering price-cap contracts to our customers, but we will continue to perform our obligations under price-cap contracts we entered into before January 1, 2007, including a one-year renewal period beginning April 1, 2010 that one of our customers is entitled to should they choose to exercise such renewal. This renewal period, if exercised, would obligate us to sell the customer approximately 2.1 million LNG gallons subject to a price cap of $7.50 per MMbtu on the SoCal Border Index. We will continue to offer fixed price contracts as appropriate and consistent with our natural gas hedging policy adopted in May 2008. Our LNG contracts provide that we charge our customers periodically based on the volume of LNG supplied.

Government Incentives

        From October 1, 2006 through December 31, 2009, we may receive a VETC of $0.50 per gasoline gallon equivalent of CNG and $0.50 per liquid gallon of LNG that we sell as vehicle fuel. Based on the service relationship we have with our customers, either we or our customers are able to claim the credit. We record 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 SFAS No. 109. 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. We expect the tax credit will continue to factor into the price we charge our customers for CNG and LNG in the future. The legislation that created this tax credit also increased the federal excise taxes on sales of CNG from $0.061 to $0.183 per gasoline gallon equivalent and on sales of LNG from $0.119 to $0.243 per LNG gallon.

Operation and Maintenance

        We generate a portion of our revenue from operation and maintenance agreements for CNG fueling stations where we do not supply the fuel. We refer to this portion of our business as "O&M."

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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 gallon equivalents sold.

Station Construction

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

Vehicle Acquisition and Finance

        In 2006, we commenced offering vehicle finance services for some of our customers' purchases of natural gas vehicles or the conversion of their existing gasoline or diesel powered vehicles to operate on natural gas. We loan to certain qualifying customers on average 60% and on occasion up to 100% of the purchase price of their natural gas vehicles. We may also lease vehicles in the future. Where appropriate, we apply for and receive state and federal incentives associated with natural gas vehicle purchases and pass these benefits through to our customers. We may also secure vehicles to place with customers or pay deposits with respect to such vehicles prior to receiving a firm order from our customers, which we may be required to purchase if our customer fails to purchase the vehicle as anticipated. Through June 30, 2009, we have not generated significant revenue from vehicle finance activities.

Landfill Gas

        In August 2008, we acquired 70% of the outstanding membership interests of DCE for a purchase price of $19.6 million including transaction costs. DCE owns a facility that collects, processes and sells biomethane from the McCommas Bluff landfill located in Dallas, Texas. From the acquisition date through December 31, 2008 and for the six months ended June 30, 2009, DCE generated approximately $1.8 million and $2.5 million, respectively, in revenue from sales of biomethane, all of which is included in our condensed consolidated statements of operations.

        On April 3, 2009, DCE entered into a fifteen year gas sale agreement with Shell Energy North America (US), L.P. ("Shell") for the sale by DCE to Shell of biomethane produced by DCE's landfill gas processing facility. The gas sale agreement calls for the sale of up to the following quantity of biomethane by DCE to Shell daily:

      April 2009 through September 2010: 4500 MMBtus per day
      October 2010 through December 2010: 5200 MMBtus per day
      Calendar year 2011: 5300 MMBtus per day
      Calendar year 2012: 5400 MMBtus per day
      Calendar year 2013: 5300 MMBtus per day
      Calendar year 2014: 5300 MMBtus per day
      Calendar year 2015-2018: 5000 MMBtus per day
      Calendar year 2019 to March 2024: 6000 MMBtus per day

        DCE's obligation and ability to sell greater than 4500 MMBtus per day is contingent on the successful permitting and commencement of commercial operation of an expansion to the existing gas processing facility to at least 15 million standard cubic feet per day inlet capacity of raw landfill gas. DCE retains the right to reserve from the gas sale agreement up to 500 MMBtus per day of biomethane for sale as a vehicle fuel. To the extent that DCE produces volumes of biomethane in excess of the volumes sold under the agreement with Shell, DCE will either attempt to sell such

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volumes at then-prevailing market prices or seek to enter into another gas sale agreement in the future. There is no guarantee that DCE will produce or be able to sell up to the maximum volumes called for under the agreement, and DCE's ability to produce such volumes of biomethane is dependent on a number of factors beyond DCE's control including, but not limited to, the availability and composition of the landfill gas that is collected, the impact on DCE's operations of the operation of the landfill by the City of Dallas and the reliability of the processing plant's critical equipment.

        The sale price for the gas under the agreement with Shell is fixed and increases in 2010 and 2011. The sale price for the gas represents a substantial premium to current prevailing prices for natural gas.

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

        The gas sale agreement is terminable by either party on 30 days' written notice if the California Energy Commission makes a written determination or adopts a ruling or regulation after the date of the agreement that the biomethane sold under the agreement will, from the date of such ruling or regulation, no longer qualify as a California Renewable Portfolio Standard eligible fuel. In addition, Shell has the right to terminate the agreement upon 30 days' written notice if the volumes of biomethane produced and delivered, calculated monthly on a rolling two-year average, are less than an annual average of 630,720 MMBtu per year (or 2,083 MMBtu per day).

Volatility of Earnings and Cash Flows Related to Natural Gas Futures Contracts

        Our earnings and cash flows historically have fluctuated significantly from period to period based on our futures activities, as all but a few of our futures contracts have not historically qualified for hedge accounting under SFAS 133. We have therefore recorded any changes in the fair market value of these contracts that did not qualify for hedge accounting directly in our statements of operations in the line item derivative (gains) losses along with any realized gains or losses generated during the period. For example, we experienced derivative gains of $5.7 million for the three months ended June 30, 2008, and derivative losses of $0.3 million, $65.0 million, $13.7 million, $6.0 million and $0.3 million for the three months ended March 31, 2006, September 30, 2006, December 31, 2006, September 30, 2008 and December 31, 2008, respectively. We had no derivative gains or losses for the three months ended June 30, 2006, March 31, 2007, June 30, 2007, September 30, 2007, December 31, 2007, March 31, 2008, March 31, 2009 and June 30, 2009 related to our futures contracts. In accordance with our natural gas hedging policy, we plan to structure all subsequent futures contracts as cash flow hedges under SFAS No. 133, but we cannot be certain that they will qualify. See "Risk Management Activities" below. If the futures contracts do not qualify for hedge accounting, we could incur significant increases or decreases in our earnings based on fluctuations in the market value of the contracts from period to period.

        Additionally, we are required to maintain a margin account to cover losses related to our natural gas futures 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

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payments could significantly impact our cash balances. At June 30, 2009, we had $2.6 million on deposit in margin accounts.

        The decrease in the value of our futures positions and any required margin deposits on our futures contracts that are in a loss position could significantly impact our financial condition in the future.

Volatility of Earnings Related to Series I Warrants

        Beginning January 1, 2009, under EITF No. 07-5, we are required to record the change in the fair market value of our Series I warrants in our financial statements. We recognized an expense of $0.2 million and $2.4 million related to recording the fair market value changes of our Series I warrants in the quarters ended March 31, 2009 and June 30, 2009, respectively.

Debt Compliance

        Our credit agreement with PCB ("Credit Agreement") requires us to comply with certain covenants. We may not incur indebtedness or liens except as permitted by the Credit Agreement, or declare or pay dividends. We must maintain, on a quarterly basis, minimum liquidity of not less than $6.0 million, accounts receivable balances, as defined, of not less than $8.0 million, consolidated net worth, as defined, of not less than $150.0 million, and a debt to equity ratio, as defined, of not more than 0.3 to 1. Beginning in the quarter ended June 30, 2009, we must also maintain a debt service ratio, as defined, of not less than 1.5 to 1 at each quarter end. Effective in the fourth quarter of 2008, we established a lock-box arrangement with PCB subject to the Credit Agreement. Funds received from our customers are remitted to the lock-box and then deposited to a PCB bank account. The remitted funds are not used to pay-down the balance of the credit agreement. However, if we default on the Credit Agreement, all of the obligations under the Credit Agreement will become due and payable and all funds received in our lock-box held by PCB will be applied to the balance due on the Credit Agreement. One of the events of default is the occurrence of a "material adverse change," which is a subjective acceleration clause. Based on the guidance in Emerging Issues Tax Force Issue No. 95-22 Balance Sheet Classification of Borrowings Outstanding under Revolving Credit Agreements That Include both a Subjective Acceleration Clause and a Lock-Box Arrangement (EITF No. 95-22), we have classified our debt pursuant to the Credit Agreement as short-term or long-term, as appropriate, and we believe an event of default is more than remote but not more likely than not. If we default on the Credit Agreement, all of the obligations under the Credit Agreement will become immediately due and payable and all funds received in our lockbox held by PCB and $2.5 million we have deposited with PCB in a payment reserve account will be applied to the balance due on the Credit Agreement. We were in compliance with the covenants as of June 30, 2009.

        One of our bank covenants is a requirement to maintain accounts receivable balances from certain subsidiaries above $8.0 million at each quarter-end during the term. To the extent natural gas prices continue to fall, which a significant portion of our revenues are derived from, or our volumes decline, we could violate this covenant in the future. Beginning with the quarter ended June 30, 2009, we are required to maintain a debt service ratio, as defined, of not less than 1.5 to 1. To the extent our operating results do not materialize as planned, we could violate this covenant in the future. In the event we violate either of these covenants, we would seek a waiver from the bank.

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Risk Management Activities

        Our risk management activities, including the revised natural gas hedging policy adopted by our board of directors in February 2007 and revised by our board of directors on May 29, 2008, are discussed in Part II, Item 7 (Management's Discussion and Analysis of Financial Condition and Results of Operation) of our 2008 Annual Report, which discussion is incorporated herein by reference.

        In an effort to mitigate the volatility of our earnings related to our futures contracts and to reduce our risk related to fixed-price sales contracts, our board of directors revisited our risk management policies and procedures and adopted a revised natural gas hedging policy in February 2007, which was amended effective May 29, 2008 and restricts our ability to purchase natural gas futures contracts and offer fixed-price sales contracts to our customers. Unless otherwise agreed in advance by the board of directors and the derivative committee, we will conduct our futures activities and enter into fixed-price sales contracts only in accordance with the natural gas hedging policy, a complete copy of which was filed as Exhibit 99.1 to our Form 8-K filed with the SEC on June 20, 2008 and is incorporated by reference herein. Pursuant to the policy, we only purchase futures contracts to hedge our exposure to variability in expected future cash flows related to a particular fixed price contract or bid. Subject to the conditions set forth in the policy, we purchase futures contracts in quantities reasonably expected to hedge effectively our exposure to cash flow variability related to such fixed-price sales contracts entered into after the date of the policy. The summary of the policy described above does not purport to be complete and is qualified in its entirety by reference to the copy of the policy previously filed.

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

Critical Accounting Policies

        For the first six months of 2009, 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 2008 Annual Report.

Recently Issued Accounting Pronouncements

        For a description of recently issued accounting pronouncements, see note 19 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
June 30,
  Six Months
Ended
June 30,
 
 
  2008   2009   2008   2009  

Statement of Operations Data:

                         

Revenue:

                         
 

Product revenues

    96.8 %   89.1 %   96.7 %   91.6 %
 

Service revenues

    3.2     10.9     3.3     8.4  
                   
   

Total revenues

    100.0     100.0     100.0     100.0  

Operating expenses:

                         
 

Cost of sales:

                         
   

Product cost of sales

    83.7     54.4     79.2     62.7  
   

Service cost of sales

    0.9     3.7     0.9     2.5  
 

Derivative (gain) loss

    (16.9 )   7.9     (9.0 )   4.1  
 

Selling, general and administrative

    35.9     41.7     37.2     39.8  
 

Depreciation and amortization

    6.5     14.8     6.7     13.3  
                   
   

Total operating expenses

    110.1     122.5     115.0     122.4  
                   

Operating loss

    (10.1 )   (22.5 )   (15.0 )   (22.4 )

Interest income (expense), net

   
0.8
   
(0.2

)
 
1.7
   
(0.2

)

Other income (expense), net

    0.0     (0.5 )   0.1     (0.3 )

Income (loss) from equity method investments

    0.0     0.1     (0.2 )   0.1  
                   
 

Loss before income taxes

    (9.3 )   (23.1 )   (13.4 )   (22.8 )

Income tax expense

    (0.2 )   (0.2 )   (0.1 )   (0.2 )
                   
 

Net loss

    (9.5 )   (23.3 )   (13.5 )   (23.0 )

Loss of noncontrolling interest in net income

        0.4         0.9  
                   
 

Net loss attributable to Clean Energy Fuels Corp. 

    (9.5 )   (22.9 )   (13.5 )   (22.1 )
                   

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008

        Revenue.     Revenue decreased by $5.9 million to $27.9 million in the three months ended June 30, 2009, from $33.8 million in the three months ended June 30, 2008. This decrease was primarily due to a decrease in our average price per gallon we charged between periods. Our effective price per gallon was $1.00 in the three months ended June 30, 2009, which represents a $0.57 per gallon decrease from $1.57 in the three months ended June 30, 2008. The decrease was primarily due to the decreased price of natural gas in the second quarter of 2009, upon which a significant amount of our revenues are based. Revenue also decreased between periods as we recorded $4.0 million of revenue related to fuel tax credits in the second quarter of 2009, compared to $4.4 million in the second quarter of 2008, and we experienced a $0.3 million decrease in station construction revenues between periods. These decreases were offset by the increase in the number of gallons delivered between periods from 18.5 million gasoline gallon equivalents to 23.7 million gasoline gallon equivalents. The increase in volume was primarily from an increase in biomethane sales (our 70% share of the biomethane sales of DCE) and CNG sales of 1.5 million and 4.5 million gallons, respectively. We believe that the biomethane sales increase was primarily attributable to our investment in new wells and the capital upgrades to the processing plant that were completed in the first quarter of 2009. The acquisition of

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four compressed natural gas operations and maintenance services contracts in May, three new refuse customers (Brookhaven Carters, CalMet Services and CleanScapes) and one new transit customer (Regional Transit Authority of Ohio) together accounted for 3.7 million gallons of the CNG volume increase. The volume growth from our joint venture in Peru and from existing refuse and airport customers contributed to the remaining CNG volume increase. Offsetting these increases is a 0.8 million gallon decrease in LNG volumes, which was primarily due to the loss of a portion of the City of Phoenix LNG supply contract for the period July 1, 2008 through June 30, 2009.

        Cost of sales.     Cost of sales decreased by $12.4 million to $16.2 million in the three months ended June 30, 2009, from $28.6 million in the three months ended June 30, 2008. Our cost of sales primarily decreased between periods as a result of our effective cost per gallon declining by $0.85 per gallon to $0.68 in the three months ended June 30, 2009, primarily due to the decreased price of natural gas in the second quarter of 2009. Offsetting this decrease was a $3.5 million increase in costs related to delivering more volume between periods. We also experienced a $0.2 million decrease in station construction costs between periods.

        Derivative (gain) loss.     Derivative (gains) losses decreased by $7.9 million to a $2.2 million loss in the three months ended June 30, 2009, from a $5.7 million gain in the three months ended June 30, 2008. The 2009 amount represents the adoption of EITF No. 07-5 that requires us to mark-to-market our Series I warrants (see note 19 to our condensed consolidated financial statements contained elsewhere herein). The 2008 amount represents a gain we recognized in the three months ended June 30, 2008 on futures contracts we purchased in April 2008 in conjunction with a fixed-price bid on a LNG supply contract we submitted. Our futures contracts we owned during the three months ended June 30, 2009 qualified for hedge accounting under SFAS 133.

        Selling, general and administrative.     Selling, general and administrative expenses decreased by $0.5 million to $11.6 million in the three months ended June 30, 2009, from $12.1 million in the three months ended June 30, 2008. Our marketing expenses decreased $2.4 million between periods as we did not incur certain advertising costs related to the Ports of Los Angeles and Long Beach and to support the Clean Alternative Fuels Act in California in the second quarter of 2009 as we did in the second quarter of 2008. This decrease was offset by a $0.9 million increase in stock option expense between periods, primarily due to options granted to our employees in December 2008 and January 2009, and an increase of $0.8 million in bonus expense between periods due to higher anticipated payouts in 2009.

        Depreciation and amortization.     Depreciation and amortization increased by $1.9 million to $4.1 million in the three months ended June 30, 2009, from $2.2 million in the three months ended June 30, 2008. This increase was primarily related to additional depreciation expense in the three months ended June 30, 2009 related to increased property and equipment balances between periods, primarily related to our expanded station network and our California LNG plant. Our June 30, 2009 amortization amount also includes amortization of the City of Dallas Landfill lease that we acquired in connection with our acquisition of DCE on August 15, 2008 and amortization of the customer contract intangible assets we obtained in connection with our acquisition of the operation and maintenance contracts we acquired during the period.

        Interest income (expense), net.     Interest income (expense), net, decreased by $325,000 to $60,000 of expense for the three months ended June 30, 2009. This decrease was primarily the result of a decrease in interest income in the three months ended June 30, 2009 due to lower average cash balances on hand during the three months ended June 30, 2009. We also incurred interest expense of $0.2 million in the second quarter of 2009, net of amounts capitalized, related to the debt we incurred to acquire our interest in DCE in August 2008 that we did not incur in the second quarter of 2008.

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        Other income (expense), net.     Other income (expense), net, was $146,000 of expense in the three months ended June 30, 2009, as compared to $2,000 of income in the three months ended June 30, 2008. The decrease was primarily related to the write-off of certain non-recoverable station costs in the three months ended June 30, 2009 that did not occur in the three months ended June 30, 2008.

        Income (loss) from equity method investments.     There was no significant change in income (loss) from equity method investments between the three months ended June 30, 2009 and the three months ended June 30, 2008.

        Loss of noncontrolling interest in net income.     During the three months ended June 30, 2009, we recorded $0.1 million of loss for the noncontrolling interest in the net loss of DCE. The noncontrolling interest represents the 30% interest of our joint venture partner. The results of DCE's operations have been included in the consolidated financial statements since August 15, 2008, the date of acquisition.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

        Revenue.     Revenue decreased by $5.7 million to $58.1 million in the six months ended June 30, 2009, from $63.8 million in the six months ended June 30, 2008. This decrease was primarily the result of a decrease in our average price per gallon between periods. Our effective price per gallon was $1.06 in the six months ended June 30, 2009, which represents a $0.44 per gallon decrease from $1.50 in the six months ended June 30, 2008. The decrease was primarily due to the decreased price of natural gas in the first six months of 2009, upon which a significant amount of our revenues are based. Revenue also decreased between periods as we recorded $8.1 million of revenue related to fuel tax credits in the first six months of 2009, compared to $9.1 million in the first six months of 2008. These decreases were offset by the increase in the number of gallons delivered between periods from 36.1 million gasoline gallon equivalents to 42.0 million gasoline gallon equivalents. A significant portion of the volume increase was due to an increase in biomethane sales (our 70% share of the biomethane sales of DCE) and CNG sales of 2.4 million and 5.0 million gallons, respectively. A significant portion of the CNG volume increase was the result of 3.2 million gallons we delivered in the second quarter of 2009 related to the acquisition of four compressed natural gas operations and maintenance services contracts in May and June, 2009. We also had volume increases of 0.5 million gallons for three new refuse customers (Brookhaven Carters, CalMet Services and CleanScapes), 0.5 million gallons related to our interest in our joint venture in Peru and 0.2 million gallons from a new transit customers (Regional Transit Authority of Ohio). The volume growth from our existing refuse and airport customers contributed to the remaining CNG volume increase. Offsetting these increases is a 1.5 million gallons decrease in LNG volumes, which was primarily due to the loss of a portion of the City of Phoenix LNG supply contract for the period July 1, 2008 through June 30, 2009. We also experienced a $4.8 million increase in station construction revenues between periods.

        Cost of sales.     Cost of sales decreased by $13.2 million to $37.8 million in the six months ended June 30, 2009, from $51.0 million in the six months ended June 30, 2008. Our cost of sales primarily decreased between periods as a result of our effective cost per gallon declining by $0.62 per gallon to $0.79 in the six months ended June 30, 2009, primarily due to the decreased price of natural gas in the first six months of 2009. Offsetting the decrease was the increase in station construction costs of $4.4 million between periods and a $4.7 million increase in costs related to delivering more volume between periods.

        Derivative (gains) losses.     Derivative (gains) losses decreased by $8.1 million to a $2.4 million loss in the six months ended June 30, 2009, from a $5.7 million gain in the six months ended June 30, 2008. The 2009 amount represents the adoption of EITF No. 07-5 that requires us to mark-to-market our Series I warrants (see note 19 to our condensed consolidated financial statements contained elsewhere herein). The 2008 amount represents a gain we recognized in the six months ended June 30, 2008 on futures contracts we purchased in April 2008 in conjunction with a fixed-price bid on a LNG supply

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contract we submitted. Our futures contracts we owned during the six months ended June 30, 2009 qualified for hedge accounting under SFAS 133.

        Selling, general and administrative.     Selling, general and administrative expenses decreased by $0.5 million to $23.2 million in the six months ended June 30, 2009, from $23.7 million in the six months ended June 30, 2008. A significant portion of this decrease related to a $3.8 million decrease in our marketing expenses between periods due to certain advertising we conducted in 2008 related to the Ports of Los Angeles and Long Beach and costs we incurred in 2008 to support the Clean Alternative Fuels Act in California that did not occur in 2009. Offsetting this decrease was an increase in stock option expense between periods of $1.9 million, primarily due to options granted to our employees in December 2008 and January 2009, and an increase of $1.3 million in salaries and benefits between periods. The salaries and benefits increase was primarily due to an increase in our bonus expense between periods due to higher anticipated payouts in 2009 and a headcount increase from 133 at June 30, 2008 to 155 at June 30, 2009.

        Depreciation and amortization.     Depreciation and amortization increased by $3.5 million to $7.7 million in the six months ended June 30, 2009, from $4.2 million in the six months ended June 30, 2008. This increase was due to additional depreciation expense in the six months ended June 30, 2008 related to increased property and equipment balances between periods, primarily related to our expanded station network and our California LNG plant. Our June 30, 2009 amortization amount also includes amortization of the identifiable intangible asset recorded in connection with the acquisition of our 70% interest in DCE in August 2008, and amortization of the customer contract intangible assets we obtained in connection with our acquisition of four operations and maintenance contracts we acquired during the period.

        Interest income, net.     Interest income, net, decreased by $1.2 million from $1.1 million of income for the six months ended June 30, 2008, to $92,000 of expense for the six months ended June 30, 2009. This decrease was primarily the result of a decrease in interest income in the six months ended June 30, 2009 due to lower average cash balances on hand between periods. We also incurred interest expense of $0.4 million in the second quarter of 2009, net of amounts capitalized, related to the debt we incurred to acquire our interest in DCE in August 2008 that we did not incur in the first six months of 2008.

        Other income (expense), net.     Other income (expense), net, was $187,000 of expense in the six months ended June 30, 2009, as compared to $40,000 of income in the six months ended June 30, 2008. The decrease was primarily related to the write-off of certain non-recoverable station costs in the six months ended June 30, 2009 that did not occur in the six months ended June 30, 2008, and the sale of certain assets in the six months ended June 30, 2008 that did not occur in the six months ended June 30, 2009.

        Income (loss) from equity method investments.     Income (loss) from equity method investments increased $192,000 to $52,000 of income for the six months ended June 30, 2009 related to our share of our joint venture in Peru.

        Loss of noncontrolling interest in net income.     During the six months ended June 30, 2009, we recorded a $0.5 million loss for the noncontrolling interest in the net loss of DCE. The noncontrolling interest represents the 30% interest of our joint venture partner. The results of DCE's operations have been included in the consolidated financial statements since August 15, 2008, the date of acquisition.

Liquidity and Capital Resources

        Historically, our principal sources of liquidity have consisted of cash provided by operations and financing activities. In May 2007, we completed our initial public offering of 10,000,000 shares of

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common stock at a public offering price of $12.00 per share. Net cash proceeds from the initial public offering were approximately $108.5 million, after deducting underwriting discounts, commissions and offering expenses. On August 15, 2008, in connection with our acquisition of 70% of the membership interests of DCE, we entered into a credit agreement with PCB pursuant to which we have borrowed $18.0 million under a term loan and an additional $7.7 million (as of June 30, 2009) under a line of credit (see note 10 to the accompanying condensed consolidated financial statements). On September 24, 2008, we sold 319,488 shares of our common stock at a price of $15.65 per share to Boone Pickens Interests, Ltd. for proceeds of approximately $5.0 million. On November 3, 2008, we sold 4,419,192 units of common stock and warrants for $7.92 per unit and we raised net proceeds of approximately $32.5 million after deducting offering costs. On July 1, 2009, we sold 9,430,000 shares of our common stock to third-party investors and received net proceeds of $73.2 million.

        In addition to funding operations, our principal uses of cash have been, and are expected to be, the construction of new fueling stations, the construction of a new LNG liquefaction plant in California, the purchase of new LNG tanker trailers, the financing of natural gas vehicles for our customers and general corporate purposes, including making deposits to support our derivative activities, geographic expansion (domestically and internationally), expanding our sales and marketing activities, support of legislative initiatives and for working capital for our expansion. We have also acquired and may continue to seek to acquire and invest in companies or assets in the natural gas and biomethane fueling infrastructure, services and production industries. We financed our operations in the first six months of 2009 primarily through cash on hand and cash provided by operations.

        At June 30, 2009, we had total cash and cash equivalents of $19.8 million, compared to $36.3 million at December 31, 2008.

        Cash provided by operating activities was $5.6 million for the six months ended June 30, 2009, compared to cash used in operating activities of $12.9 million for the six months ended June 30, 2008. The increase in operating cash flow resulted primarily from improved operating results between periods, and increased collections of accounts and other receivables between periods of $3.7 million and a net return of $5.2 million in LNG truck deposits between periods. The remaining changes primarily resulted from changes in working capital balances, which were mostly due to timing differences related to the various cash flows between periods.

        Cash used in investing activities was $24.5 million for the six months ended June 30, 2009, compared to $32.6 million for the six months ended June 30, 2008. Our purchases of property and equipment were $18.2 million during the first six months of 2009, compared to $36.7 million for the same period in 2008. We also acquired four compressed natural gas operations and maintenance services contracts for $5.6 million during the second quarter of 2009. We made additional investments during the first six months of 2009 totaling $2.0 million in the Vehicle Production Group, LLC, a company developing a CNG taxi and a paratransit vehicle. In June 2009, we sold certain customer vehicle loans to a bank for net proceeds of $1.3 million. In the first six months of 2008, we purchased $43.4 million of short-term investments with our initial public offering proceeds from May 2007, of which $47.5 million matured or were sold during the period. We did not have any short-term investments during the first six months of 2009.

        Cash provided by financing activities for the six months ended June 30, 2009 was $2.4 million, compared to $103,000 for the six months ended June 30, 2008. In February 2009, we borrowed an additional $3.1 million from PCB to fund capital expenditures for an upgrade to DCE's biomethane plant. This increase in cash was offset by repayments on our capital lease and long-term debt instruments of $0.7 million.

        Our financial position and liquidity are, and will be, influenced by a variety of factors, including our ability to generate cash flows from operations, deposits and margin calls on our futures positions, the level of any outstanding indebtedness and the interest we are obligated to pay on this indebtedness,

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

Capital Expenditures

        Our current business plan calls for approximately $14.9 million in additional capital expenditures from July 1, 2009 through the end of 2009, primarily related to construction of new fueling stations. In addition, we anticipate that during the remainder of 2009 we will provide approximately $0.3 million for financing natural gas vehicle purchases by our customers and up to $2.5 million in financing that we may be required to provide to the Vehicle Production Group LLC, a company that is developing CNG paratransit vehicles and taxis. Through August 7, 2009, we have $4.4 million in debt financing outstanding under our loan agreement with DCE and we anticipate that we will provide up to approximately $6.8 million in additional loan financing to DCE during the remainder of 2009 for additional capital expenditures and expenses. Financing provided to DCE is not included in our 2009 capital expenditure business plan. We anticipate that we will fund all additional financing we provide to DCE through available cash reserves or our $12.0 million Facility B loan with PCB, which has approximately $4.3 million in remaining available credit as of August 7, 2009 which may be accessed through August 14, 2009. We intend to fund our principal liquidity requirements over the next twelve months, other than our loan to DCE, through cash and cash equivalents and cash provided by operations. If we have significant unanticipated capital expenditures, investments, acquisitions or operating expenses, we may seek to raise capital to fund such capital expenditures, investments, acquisitions or expenses. Due to the continuing disruption in the capital markets, we may not be able to raise capital on terms that are favorable to existing stockholders or at all. Any inability to raise capital may impair our ability to invest in new stations, develop natural gas fueling infrastructure and invest in strategic transactions or acquisitions and reduce our ability to invest in our business and generate increased revenues.

        Our credit agreement with PCB requires that we comply with certain covenants, as detailed in footnote 10 of our condensed consolidated financial statements contained elsewhere herein. One of the covenants requires that we maintain accounts receivable balances from certain subsidiaries above $8.0 million at each quarter-end during the term. To the extent natural gas prices continue to fall, which would result in decreased revenues, or our volumes sold decline, we could violate this covenant in the future. Also, beginning with the quarter ending June 30, 2009, we are required to maintain a debt service ratio, as defined, of 1.5 to 1. Should our operating results not materialize as planned, we could violate this covenant in the future. If we were to violate a covenant, we would seek a waiver from the bank, which the bank is not obligated to grant. If the bank does not grant a waiver, all of the obligations under the credit agreement will become immediately due and payable and $2.5 million of our funds held by PCB would be applied to the balance due on the PCB loans. We also would be unable to use the PCB line of credit to fund our loan to DCE if this were to occur. We were in compliance with all of the covenants as of June 30, 2009.

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Contractual Obligations

        The following represents the scheduled maturities of our contractual obligations as of June 30, 2009:

 
  Payments Due by Period  
Contractual Obligations:
  Total   Remainder of
2009
  2010 and
2011
  2012 through
2014
  2015 and
beyond
 

Long-term debt and capital lease obligations(a)

  $ 32,584,763   $ 2,941,065   $ 7,568,692   $ 21,764,949   $ 310,057  

Operating lease commitments(b)

    15,660,188     944,666     3,681,637     4,913,505     6,120,380  

"Take-or-pay" LNG purchase contracts(c)

    4,004,000     1,011,500     2,992,500          

Construction contracts(d)

    7,982,818     7,982,818              
                       

Total

  $ 60,231,769   $ 12,880,049   $ 14,242,829   $ 26,678,454   $ 6,430,437  
                       

(a)
Consists of long-term debt and capital lease obligations to finance equipment purchases, including interest.

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

(c)
The amounts in the table represent our estimates for our fixed LNG purchase commitments under two "take or pay" contracts. In October 2007, we entered into a 10-year contingent take-or-pay commitment for 45,000 LNG gallons per day from an LNG plant to be constructed in Arizona, which commitment is not reflected in the table above because the obligation is contingent on the completion of construction of the LNG plant, which is anticipated to occur in the third quarter of 2009.

(d)
Consists of our obligations to fund various fueling station construction projects, net of amounts funded through June 30, 2009, and excluding contractual commitments related to station sales contracts.

Off-Balance Sheet Arrangements

        At June 30, 2009, we had the following off-balance sheet arrangements:

    outstanding surety bonds for construction contracts and general corporate purposes totaling $7.6 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 or index-plus prices subject to a price cap.

        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.

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        We have entered into contracts with two vendors to purchase LNG that require us to purchase minimum volumes from the vendors. One of the contracts expired in July 2009 and the other contract expires in June 2011. The minimum commitments under these two contracts are included in the table set forth under "Take-or-pay" LNG purchase contracts above. In October 2007, we entered into a contingent take-or-pay contract from an LNG plant that is not included in the table above as it is contingent on the LNG plant being constructed. We anticipate construction of the plant will be completed in the third quarter of 2009.

        We have entered into operating lease arrangements for certain equipment and for our office and field operating locations in the ordinary course of business. The terms of our leases expire at various dates through 2016. Additionally, in November 2006, we entered into a ground lease for 36 acres in California on which we built our California LNG liquefaction plant. The lease is for an initial term of payments of $230,000 per year, plus up to $130,000 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 for certain other services that the landlord will provide. Commercial operations began December 1, 2008, and the payments for this lease are included in "Operating lease commitments" in the "Contractual Obligations" table set forth above.

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

Item 3.—Quantitative and Qualitative Disclosures about Market Risk

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

        Natural gas costs represented 60% of our cost of sales for 2008 and 44% of our cost of sales for the six months ended June 30, 2009. Prices for natural gas over the nine-year and six-month period from December 31, 1999 through June 30, 2009, based on the NYMEX daily futures data, have ranged from a low of $1.65 per Mcf to a high of $19.38 per Mcf. At June 30, 2009, the NYMEX index price of natural gas was $3.54 per Mcf.

        To reduce price risk caused by market fluctuations in natural gas, we may enter into exchange traded natural gas futures contracts. These arrangements also expose us to the risk of financial loss in situations where the other party to the contract defaults on its contract or there is a change in the expected differential between the underlying price in the contract and the actual price of natural gas we pay at the delivery point.

        We account for these futures contracts in accordance with SFAS 133. Under this standard, the accounting for changes in the fair value of a derivative depends upon whether it has been designated in a hedging relationship and, further, on the type of hedging relationship. To qualify for designation in a hedging relationship, specific criteria must be met and appropriate documentation maintained. Our futures contracts did not qualify for hedge accounting under SFAS 133 for the years ended December 31, 2005 and 2006, and we did not have any derivative activity in 2007. Consequently, any changes in the fair value of the derivatives during 2005 and 2006 were recorded directly to our consolidated statements of operations. In 2008, we had certain contracts that did not qualify for hedge accounting and we had two derivative contracts to hedge two fixed supply contracts that did qualify for

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hedge accounting. During the six month period ended June 30, 2009, we had certain futures contracts that did qualify for hedge accounting.

        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 changing market conditions. The net effect of the realized and unrealized gains and losses related to these derivative instruments for the year ended December 31, 2006 was a $79.0 million decrease to pre-tax income. We did not have any futures contracts outstanding during the year ended December 31, 2007. In an effort to mitigate the volatility in our earnings related to futures activities, in February 2007, our board of directors adopted a revised natural gas hedging policy which restricts our ability to purchase natural gas futures contracts and offer fixed-price sales contracts to our customers. This policy was further revised by our board of directors in May 2008. We plan to structure prospective futures contracts so that they will be accounted for as cash flow hedges under SFAS 133, but we cannot be certain they will qualify. For more information, please read "—Risk Management Activities" above.

        We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to futures contracts we hold as of June 30, 2009 to hedge the fixed-price component of certain supply contracts. If the price of natural gas were to fluctuate (increase or decrease) by 10% from the price quoted on NYMEX on June 30, 2009 ($3.54 per Mcf), we could expect a corresponding fluctuation in the value of the contracts of approximately $1.4 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 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 the report.

Changes in Internal Control over Financial Reporting

        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 may become party to various legal actions that arise 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. We are currently being audited by the IRS for tax years 2005 through 2007. 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 we may incur resulting from any lawsuits, claims and proceedings, audits, commitments, contingencies and related matters or the timing if these liabilities, if any. If these matters were to be ultimately resolved

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unfavorably, an outcome not currently anticipated, it is possible that such outcome could have a material adverse effect upon our consolidated financial position or results of operations. However, we believe that the ultimate resolution of such actions will not have a material adverse affect on our consolidated financial position, results of operations, or liquidity.

Item 1A.—Risk Factors

         An investment in our company involves a high degree of risk of loss. You should carefully consider the risk factors discussed below together with the risk factors in Part I, Item 1A of our 2008 Annual Report and all of the other information included in this report before you decide to purchase shares of our common stock. We believe the risks and uncertainties described below are the most significant we face. The occurrence of any of the following risks could harm our business. In that case, the trading price of our common stock could decline. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also impair our operations.

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

        For the six month period ended June 30, 2009, we incurred pre-tax losses of $13.2 million, which included derivative losses of $2.4 million. In 2006, 2007 and 2008 we incurred pre-tax losses of $89.8 million, $7.7 million, and $44.3 million, respectively. Our loss for 2006 included $79.0 million in derivative losses and our loss for 2008 included $18.6 million in expenses associated with our support for Proposition 10, the California Alternative Fuel Vehicles and Renewable Energy ballot initiative. For the six month period ended June 30, 2009, our loss was decreased by our receipt of approximately $8.1 million of revenue from federal fuel tax credits. During 2007 and 2008, our losses were decreased by our receipt of approximately $17.0 million and $17.2 million of revenue, respectively, from federal fuel tax credits. The law providing for the fuel tax credits is scheduled to expire December 31, 2009. In order to execute our strategy and improve our financial performance, we must continue to invest in developing the natural gas vehicle fuel market and offer our customers compelling natural gas fuel prices. If our natural gas sales activities and station operations do not achieve or maintain profitability that can be sustained in the absence of federal fuel tax credits, our business will suffer and the price of our common stock may drop.

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

        Prices of oil, gasoline and diesel fuel have declined rapidly from summer 2008 levels. The price of a barrel of crude oil has declined from a high of $148.35 per barrel reached on July 11, 2008 to a price of $69.89 per barrel on June 30, 2009. Average retail prices for ultra low sulfur diesel fuel in California have declined from a high of $5.03 in May and June 2008 to $2.79 per gallon at June 30, 2009 and average retail prices for gasoline in California have declined from a high of $4.59 per gallon in June 2008 to $2.98 per gallon at June 30, 2009. The decrease in the price of diesel and gasoline, in particular, has resulted in reduced interest in alternative fuels such as LNG and CNG. Decreased interest in alternative fuels will slow the growth of our business. In addition, to the extent that we price our CNG and LNG fuel at a discount to these reduced diesel or gasoline prices in an effort to attract new and retain existing customers, our profit margin on fuel sales may be harmed and our financial results negatively impacted. Our retail prices for LNG fuel in California decreased from $3.70 per diesel gallon equivalent in June and July of 2008 to $2.05 per diesel gallon equivalent at June 30, 2009 and our retail prices for CNG fuel sold in the Los Angeles Basin decreased from a high of $3.30 per GGE in July of 2008 to $2.30 per GGE at June 30, 2009. Lower fuel prices for CNG and LNG also will reduce our revenues.

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Failure to comply with the terms of our Credit Agreement with PlainsCapital Bank could impair our rights in DCE and other secured property.

        In August 2008, we acquired a 70% interest in DCE, which manages a biomethane production facility at the McCommas Bluff landfill in Dallas, Texas and holds a lease to the associated landfill gas development rights. We borrowed $18 million from PCB to fund the acquisition and obtained a $12 million line of credit from PCB to pay certain costs and expenses of the acquisition and finance capital improvements of the gas processing plant through a loan made by us to DCE. We have used $7.7 million of the line of credit from PCB as of June 30, 2009. To secure our obligations under the Credit Agreement, we granted PCB a security interest in 45 of our LNG tanker trailers, certain accounts receivable and inventory, and our note receivable from, and our membership interests in, DCE. Our Credit Agreement with PCB requires that we comply with certain covenants. One of the covenants requires that we maintain accounts receivable balances from certain subsidiaries above $8 million at each quarter-end during the term. To the extent natural gas prices fall, which would result in decreased revenues, or our volumes sold decline, we could violate this covenant in the future. Also, beginning with the quarter ending June 30, 2009, we are required to maintain a debt service ratio, as defined, of 1.5 to 1.0. Should our operating results not materialize as planned, we could violate this covenant in the future. If we were to violate a covenant, we would seek a waiver from the bank, which the bank is not obligated to grant. If the bank does not grant a waiver, all of the obligations under the Credit Agreement will become immediately due and payable and $2.5 million of our funds held by PCB would be applied to the balance due on the PCB loans. We also would be unable to use the PCB line of credit to fund our loan to DCE if this were to occur.

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

        Natural gas vehicles cost more than comparable gasoline or diesel powered vehicles because converting a vehicle to use natural gas adds to its base cost. If the prices of CNG and LNG do not remain sufficiently below the prices of gasoline or diesel, fleet operators may be unable to recover the additional costs of acquiring or converting to natural gas vehicles in a timely manner, and they may choose not to use natural gas vehicles. Recent and significant volatility in oil and gasoline prices demonstrate that it is difficult to predict future transportation fuel costs. The decline in the price of oil, diesel fuel and gasoline from summer 2008 levels has reduced the economic advantages that our existing or potential customers may realize by using less expensive CNG or LNG fuel as an alternative to gasoline or diesel. The reduced prices for gasoline and diesel fuel and continuing uncertainty about fuel prices, combined with higher costs for natural gas vehicles, may cause potential customers to delay or reject converting their fleets to run on natural gas. In that event, our growth would be slowed and our business would suffer.

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

        In the recent past, the price of natural gas has been volatile, and this volatility may continue. From the end of 1999 through the end of 2008, the price for natural gas, based on the NYMEX daily futures data, ranged from a low of $1.65 per Mcf to a high of $19.38 per Mcf. As of August 1, 2009, the NYMEX index price for natural gas was $3.37 per Mcf. Increased natural gas prices affect the cost to us of natural gas and will adversely impact our operating margins in cases where we have committed to sell natural gas at a fixed price without a futures contract or with an ineffective futures contract that does not fully mitigate the price risk or where we otherwise cannot pass on the increased costs to our customers. In addition, higher natural gas prices may cause CNG and LNG to cost as much as or more than gasoline and diesel generally, which would adversely impact the adoption of CNG and LNG as a

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vehicle fuel. Conversely, lower natural gas prices reduce our revenues. Among the factors that can cause price fluctuations in natural gas prices are changes in domestic and foreign supplies of natural gas, domestic storage levels, crude oil prices, the price difference between crude oil and natural gas, price and availability of alternative fuels, weather conditions, level of consumer demand, economic conditions, price of foreign natural gas imports, and domestic and foreign governmental regulations and political conditions. The recent economic recession and increased domestic natural gas supplies have contributed to significant and rapid declines in the price of natural gas.

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

        Our business depends in part on environmental regulations and programs in the United States that promote or mandate the use of cleaner burning fuels, including natural gas for vehicles. In particular, the Ports of Los Angeles and Long Beach have adopted the San Pedro Bay Ports Clean Air Action Plan, which outlines a Clean Trucks Program that calls for the replacement of 16,000 drayage trucks with trucks that meet certain clean truck standards. Industry participants with a vested interest in gasoline and diesel, many of which have substantially greater resources than we do, invest significant time and money in an effort to influence environmental regulations in ways that delay or repeal requirements for cleaner vehicle emissions. In addition, various lawsuits have been filed to block parts of the Clean Trucks Program which may delay the program's implementation. Further, an economic recession may result in the delay, amendment or waiver of environmental regulations or the Clean Trucks Program due to the perception that they impose increased costs on the transportation industry that cannot be absorbed in a contracting economy. The delay, repeal or modification of federal or state regulations or programs that encourage the use of cleaner vehicles, and in particular the Clean Trucks Program outlined in the San Pedro Bay Ports Clean Air Action Plan, could have a detrimental effect on the U.S. natural gas vehicle industry, which, in turn, could slow our growth and adversely affect our business.

Our growth depends in part on tax and related government incentives for clean burning fuels. A reduction in these incentives would increase the cost of natural gas fuel and vehicles for our customers and could significantly reduce our revenue.

        Our business depends in part on tax credits, rebates and similar federal, state and local government incentives that promote the use of natural gas as a vehicle fuel in the United States. The federal excise tax credit of $0.50 per gasoline gallon equivalent of CNG and liquid gallon of LNG sold for vehicle fuel use, which began on October 1, 2006, is scheduled to expire December 31, 2009. Based on the service relationship we have with our customers, either we or our customers are able to claim the credit. In 2007 and 2008, we recorded approximately $17.0 million and $17.2 million of revenue, respectively, related to fuel tax credits, representing approximately 14.5% and 13.7%, respectively, of our total revenue during the period. For the six-month periods ended June 30, 2008, and June, 30, 2009, we recorded $9.1 million and $8.1 million of revenue, respectively, related to fuel tax credits, representing approximately 14.3% and 13.9%, respectively, of our total revenue during the period. The failure to extend the federal excise tax credit for natural gas, or the repeal of federal or state tax credits for the purchase of natural gas vehicles or natural gas fueling equipment, could have a detrimental effect on the natural gas vehicle industry, which, in turn, could adversely affect our business and results of operations. In addition, if grant funds were no longer available under existing government programs, the purchase of or conversion to natural gas vehicles and station construction could slow and our business and results of operations could be adversely affected. Any reduction in tax revenues associated with an economic recession or slow-down could result in a significant reduction in funds available for government grants that support vehicle conversion and station construction and impair our ability to grow our business.

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

        To expand our business, we must develop new fleet customers and obtain and fulfill CNG and LNG fueling contracts from these customers. We cannot guarantee that we will be able to develop these customers or obtain these fueling contracts. Whether we will be able to expand our customer base will depend on a number of factors, including: the level of acceptance and availability of natural gas vehicles, the growth in our target markets of fueling station infrastructure that supports CNG and LNG sales and our ability to supply CNG and LNG at competitive prices. The decline in oil, diesel and gasoline prices from summer 2008 levels has resulted in decreased interest in alternative fuels like CNG and LNG. In addition, the disruption in the capital markets that began in 2008 has reduced the availability of debt financing to support the purchase of CNG and LNG vehicles and investment in the CNG and LNG infrastructure. If our potential customers are unable to access credit to purchase natural gas vehicles it may make it difficult or impossible for them to invest in natural gas vehicle fleets, which would impair our ability to grow our business.

We may need to raise debt or equity capital to fund increased capital expenditures, unanticipated expenses or for any potential acquisitions, and an inability to access the capital markets may impair our ability to invest in our business.

        In order to fund unanticipated capital expenditures, expenses, or investments, or to provide resources for potential acquisition activity, we may need to pursue additional equity or debt financing options, which may not be available on terms favorable to us or at all. Recent economic turmoil and lack of liquidity in the debt capital markets and volatility and lower prices in the equity capital markets have adversely affected capital raising opportunities. If we are unable to obtain debt or equity financing in amounts sufficient to fund any unanticipated capital expenditures, unanticipated expenses, investments or potential acquisition activity, we will be forced to suspend or curtail these capital expenditures or postpone or delay the investments or potential acquisitions or other strategic transactions, which could harm our business, results of operations, and future prospects.

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

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

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

        Limited availability of natural gas vehicles restricts their wide scale introduction and narrows our potential customer base. Currently, original equipment manufacturers produce a small number of natural gas engines and vehicles, and they may not make adequate investments to expand their natural gas engine and vehicle product lines. For the North American market, there is only one automobile manufacturer that makes natural gas powered passenger vehicles, and manufacturers of medium and heavy-duty vehicles produce only a narrow range and number of natural gas vehicles. The technology utilized in some of the heavy-duty vehicles that run on LNG is also relatively new and has not been

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previously deployed or used in large numbers of vehicles. As a result, these vehicles may require servicing and further technology refinements to address performance issues that may occur as vehicles are deployed in large numbers and are operated under strenuous conditions. If potential heavy duty LNG truck purchasers are not satisfied with truck performance, it may delay or impair the growth of our LNG fueling business. Further, North American car and truck manufacturers are facing significant economic challenges that may make it difficult or impossible for them to introduce new natural gas vehicles in the North American market or continue to manufacture and support the limited number of available natural gas vehicles. Due to the limited supply of natural gas vehicles, our ability to promote natural gas vehicles and our sales may be restricted, even if there is demand.

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

        Conversion of vehicle engines from gasoline or diesel to natural gas is performed by only a small number of vehicle conversion suppliers that must meet stringent safety and engine emissions certification standards. The engine certification process is time consuming and expensive and raises vehicle costs. In addition, conversion of vehicle engines from gasoline or diesel to natural gas may result in vehicle performance issues or increased maintenance costs which could discourage our potential customers from purchasing converted vehicles that run on natural gas. Without an increase in vehicle conversion options, vehicle choices for fleet use will remain limited and our sales may be restricted, even if there is demand.

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

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

Our ability to supply LNG to new and existing customers is restricted by limited production of LNG and by our ability to source LNG without interruption and near our target markets.

        Production of LNG in the United States is fragmented. LNG is produced at a variety of smaller natural gas plants around the United States as well as at larger plants where it is a byproduct of their primary natural gas production. It may become difficult for us to obtain additional LNG without interruption and near our current or target markets at competitive prices. If our LNG liquefaction plants, or any of those from which we purchase LNG, are damaged by severe weather, earthquake or other natural disaster, or otherwise experience prolonged downtime, our LNG supply will be restricted.

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If we are unable to supply enough of our own LNG or purchase it from third parties to meet existing customer demand, we may be liable to our customers for penalties. An LNG supply interruption would also limit our ability to expand LNG sales to new customers, which would hinder our growth. Furthermore, because transportation of LNG is relatively expensive, if we are required to supply LNG to our customers from distant locations, our operating margins will decrease on those sales.

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

        Some of our LNG supply agreements have take or pay commitments and our California LNG liquefaction plant has land lease and other fixed operating costs regardless of production and sales levels. Should the market demand for LNG decline or if demand under any existing or any future LNG supply contract does not maintain its volume levels or grow, overall operating and supply costs may increase and negatively impact our margins.

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

        Two third-party LNG suppliers, Williams Gas Processing Company and ExxonMobil Corporation, supplied approximately 47% of the LNG we sold for the year ended December 31, 2007 and supplied 49% of the LNG we sold for the year ended December 31, 2008. For the six-month period ended June 30, 2009, Williams Gas Processing Company and ExxonMobil Corporation supplied approximately 26% of the LNG we sold. Under certain circumstances, Williams Gas Processing Company may terminate our supply contract on short notice. Williams may also significantly increase the price of LNG we purchase upon 24 hours' notice if Williams' costs to produce LNG increases, and we may be required to reimburse Williams Gas Processing Company for certain other expenses. Our contract with Williams Gas Processing Company, which supplied 32% of the LNG we sold for the year ended December 31, 2007, 29% for the year ended December 31, 2008, and 11% for the first six months of 2009, expires on June 30, 2011. Our contract with ExxonMobil Corporation, which supplied 15% of the LNG we sold for the year ended December 31, 2007, 20% for the year ended December 31, 2008, and 15% for the first six months of 2009, expired July 31, 2009. Furthermore, there are a limited number of LNG suppliers in or near the areas where our LNG customers are located. It may be difficult to replace an LNG supplier, and we may be unable to obtain alternate suppliers at acceptable prices, in a timely manner or at all. If significant supply interruptions occur, our ability to meet customer demand will be impaired, customers may cancel orders and we may be subject to supply interruption penalties. If we are subject to LNG price increases, our operating margins may be impaired and we may be forced to sell LNG at a loss under our LNG supply contracts.

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

        Some regions of the United States and Canada depend heavily on natural gas supplies coming from particular fields or pipelines. Interruptions in field production or in pipeline capacity could reduce the availability of natural gas or possibly create a supply imbalance that increases natural gas prices. We have in the past experienced LNG supply disruptions due to severe weather in the Gulf of Mexico and plant outages. If there are interruptions in field production, pipeline capacity, equipment failure, liquefaction production or delivery, we may experience supply stoppages which could result in our inability to fulfill delivery commitments. This could result in our being liable for contractual damages and daily penalties or otherwise adversely affect our business.

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

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

We are in the process of commencing operations at a new LNG liquefaction plant, which could cost more to operate than we estimate and divert resources and management attention.

        We are in the initial stages of operating our LNG liquefaction plant in California, which began producing LNG in November 2008. The implementation and operation of any plant of this nature has inherent risks. Permitting, environmental issues, a lack of materials and a lack of human resources, among other factors, could complicate our ability to operate the LNG liquefaction plant and affect the operation of the plant. The new facility could also present increased financial exposure through start-up delays, repairs and incomplete production capability. If the new plant has higher than expected operating costs and is not able to produce expected amounts of LNG, we may be forced to sell LNG at a price below production costs and we may lose money. Additionally, if the quality of LNG produced at the plant does not meet contractual specifications, our customers may not be required to purchase it, which would harm our business.

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

        From 2005 to 2008, we sold and delivered approximately 30% of our total gasoline gallon equivalents of CNG and LNG under contracts that provided a fixed price or a price cap to our customers over terms typically ranging from one to three years, and in some cases up to five years. At any given time, however, the market price of natural gas may rise and our obligations to sell fuel under fixed price contracts may be at prices lower than our fuel purchase or production price if we do not have effective futures contracts in place. This circumstance has in the past and may again in the future compel us to sell fuel at a loss, which would adversely affect our results of operations and financial condition. Commencing with the adoption of our revised natural gas hedging policy in February 2007, we expect to purchase futures contracts to hedge our exposure to variability related to our fixed price contracts. However, such contracts may not be available or we may not have sufficient financial resources to secure such contacts. In addition, under our hedging policy, we may reduce or remove futures contracts we have in place related to these contracts if such disposition is approved in advance by our board of directors and derivative committee. If we are not economically hedged with respect to our fixed price contracts, we will lose money in connection with those contracts during periods in which natural gas prices increase above the prices of natural gas included in our customers' contracts. As of June 30, 2009, we were economically hedged with respect to four of our fixed price contracts with our customers.

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

        Our purchase of futures contracts can result in substantial losses under various circumstances, including if we do not accurately estimate the volume requirements under our fixed price or price cap customer contracts when determining the volumes included in the futures contracts we purchase, or we are required to purchase a futures contract in connection with a bid proposal and ultimately we are not awarded the entire contract or our customer does not fully perform its obligations under the awarded contract. We also could incur significant losses if a counterparty does not perform its obligations under

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the applicable futures arrangement, the futures arrangement is economically imperfect or ineffective, or our futures policies and procedures are not properly followed or do not work as planned. Furthermore, we cannot assure that the steps we take to monitor our futures activities will detect and prevent violations of our risk management policies and procedures.

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

        We are required to maintain a margin account to cover losses related to our natural gas futures contracts. Futures contracts are valued daily, and if our contracts are in loss positions at the end of a trading day, our broker will transfer the amount of the losses from our margin account to a clearinghouse. If at any time the funds in our margin account drop below a specified maintenance level, our broker will issue a margin call that requires us to restore the balance. Payments we make to satisfy margin calls will reduce our cash reserves, adversely impact our liquidity and may also adversely impact our ability to expand our business. Moreover, if we are unable to satisfy the margin calls related to our futures contracts, our broker may sell these contracts to restore the margin requirement at a substantial loss to us. At June 30, 2009, we had $2.6 million on deposit related to our futures contracts.

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

        We account for our futures activities under SFAS 133, which requires us to value our futures contracts at fair market value in our financial statements. Our futures contracts historically have not qualified for hedge accounting, and therefore we have recorded any changes in the fair market value of these contracts directly in our consolidated statements of operations in the line item "derivative (gains) losses" along with any realized gains or losses during the period. Currently, we attempt to qualify all of our futures contracts for hedge accounting under SFAS 133, but there can be no assurances that we will be successful in doing so. At June 30, 2009, 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 and stockholders' equity in the future based on fluctuations in the market value of our futures contracts from quarter to quarter. For example, we experienced a derivative gain of $33.1 million and $5.7 million for the three months ended September 30, 2005 and June 30, 2008, respectively, and experienced derivative losses of $19.9 million, $0.3 million, $65.0 million, $13.7 million, $6.0 million and $0.3 million for the three months ended December 31, 2005, March 31, 2006, September 30, 2006, December 31, 2006, September 30, 2008 and December 31, 2008, respectively. We had no derivative gains or losses for the three months ended June 30, 2006, March 31, 2007, June 30, 2007, September 30, 2007, December 31, 2007, March 31, 2008, March 31, 2009 and June 30, 2009. 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, or the Global Warming Solutions Act, which calls for a cap on greenhouse gas emissions throughout California and a statewide reduction to 1990 levels by 2020, and an additional 80% reduction below 1990 levels by 2050. Seven western U.S. states (Arizona, California, Montana, New Mexico, Oregon, Utah and Washington) and four Canadian provinces (British Columbia, Manitoba, Ontario and Quebec) formed the Western Climate Initiative to help combat climate change. Other states and the federal government are considering passing measures to regulate and reduce greenhouse gas emissions. Any of these regulations, when and if implemented, may regulate the greenhouse gas emissions produced by our LNG production plants in California and Texas

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or our LNG and CNG fueling stations and require that we obtain emissions credits or invest in costly emissions prevention technology. We cannot currently estimate the potential costs associated with federal or state regulation of greenhouse gas emissions from our LNG plants or LNG and CNG stations and these unknown costs are not contemplated in the financial terms of our customer agreements. These unanticipated costs may have a negative impact on our financial performance and may impair our ability to fulfill customer contracts at an operating profit.

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

        Natural gas operations entail inherent risks, including equipment defects, malfunctions and failures and natural disasters, which could result in uncontrollable flows of natural gas, fires, explosions and other damages. For example, operation of LNG pumps requires special training and protective equipment because of the extreme low temperatures of LNG. LNG tanker trailers have also in the past been, and may in the future be, involved in accidents that result in explosions, fires and other damage. Improper refueling of LNG vehicles can result in venting of methane gas. Additionally, CNG fuel tanks if damaged or improperly maintained may rupture and the contents of the tank may rapidly decompress and result in death or injury. In 2007, a driver of a CNG van in Los Angeles was killed when the previously damaged tanks he was fueling exploded. These risks may expose us to liability for personal injury, wrongful death, property damage, pollution and other environmental damage. We may incur substantial liability and cost if damages are not covered by insurance or are in excess of policy limits.

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

        Our operations to date have been concentrated in California and Arizona. For the years ended December 31, 2007 and 2008, sales in California accounted for 40% and 45% respectively, and sales in Arizona accounted for 20% and 14%, respectively, of the total amount of gallons we delivered. For the six month period ended June 30, 2009, sales in California and Arizona accounted for 50% and 9%, respectively, of the total amount of gallons we delivered. A decline in the economy in these areas could slow the rate of adoption of natural gas vehicles, reduce fuel consumption or reduce the availability of government grants, any of which could negatively affect our growth.

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

        We loan to certain qualifying customers on average 60% and occasionally up to 100% of the purchase price of natural gas vehicles. We may also lease vehicles to customers in the future. There are risks associated with providing financing or leasing that could cause us to lose money. Some of these risks include: most of the equipment financed consists of vehicles, which are mobile and easily damaged, lost or stolen, there is a risk the borrower may default on payments, we may not be able to bill properly or track payments in adequate fashion to sustain growth of this service, and the amount of capital available to us is limited and may not allow us to make loans required by customers. Some of our customers, such as taxi owners, may depend on the CNG vehicles that we finance as their sole source of income, which may make it difficult for us to recover the collateral in a bankruptcy proceeding. The continued disruption in the credit markets may further reduce the amount of capital available to us and an economic recession or continued economic contraction may increase the rate of default by borrowers, leading to an increase in losses on our loan portfolio. As of June 30, 2009, we had $3.7 million outstanding in loans provided to customers to finance natural gas vehicle purchases.

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We may incur losses and use working capital, if we are unable to place with customers the natural gas vehicles that we or our business partners order from manufacturers.

        To ensure availability for our customers, from time to time we enter into binding purchase agreements for natural gas vehicles when there is a production lead time. Although we attempt to arrange for customers to purchase the vehicles before delivery to us, we may be unable to locate purchasers on a timely basis and consequently may need to take delivery of and title to the vehicles. These purchases would adversely affect our cash reserves until such time as we can sell the vehicles to our customers, and we may be forced to sell the vehicles at a loss. At June 30, 2009, we had $4.2 million in aggregate deposits outstanding on natural gas vehicles which are described below.

        In July 2006, we entered into an agreement with Inland Kenworth, Inc. (Inland) pursuant to which we agreed to deposit certain amounts with Inland, as security for a guarantee, to fund the acquisition by Kenworth Truck Company ("Kenworth") of 100 LNG trucks. At June 30, 2009, we had outstanding $1.5 million of deposits under this agreement. We also entered into two deposit agreements with Westport Innovations, Inc. ("Westport") in 2007 to facilitate the production of LNG fuel systems for installation in the tractors purchased by Inland. At June 30, 2009, we had outstanding a total of $1.3 million on deposits made to Westport under these agreements. Repayment of these deposits will occur incrementally upon the sale of the converted tractors to customers; however, to the extent an LNG fuel system incorporated into a tractor is not sold within 24 months of the effective date of the applicable deposit agreement (or such other time period as is agreed by both us and Westport), Westport is not obligated to repay any of the deposit with respect to such LNG fuel systems. In addition, we have approximately $1.4 million on deposit at June 30, 2009 to secure the availability of 57 Honda Civic natural gas vehicles.

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

        We have existing, and will continue to seek, long-term LNG and CNG station construction, maintenance and fuel sales contracts with various federal, state and local governmental bodies, which accounted for approximately two-thirds of our revenues from 2006 through 2008. In May 2009, we spent $5.6 million to acquire four new CNG operation and maintenance contracts with government agencies. In addition to our normal business risks, our contracts with these government entities are often subject to unique risks, some of which are beyond our control. Long-term government contracts and related orders are subject to cancellation if appropriations for subsequent performance periods are not made. The termination of funding for a government program supporting any of our CNG or LNG operations could result in a loss of anticipated future revenues attributable to that program, which could have a negative impact on our operations. In addition, government entities with whom we contract are often able to modify, curtail or terminate contracts with us without prior notice at their convenience, and are only liable for payment for work done and commitments made at the time of termination. Modification, curtailment or termination of significant contracts could have a material adverse effect on our results of operations and financial condition. In particular, if any of the contracts we recently acquired are terminated, we may be unable to recover our investment in acquiring the contracts. Further, many governmental entities are experiencing significant budget deficits as a result of the economic recession, which has and may continue to reduce or curtail their ability to fund natural gas fuel programs, purchase natural gas vehicles or provide public transportation and services, which would harm our business.

Our business is subject to a variety of governmental regulations that may restrict our business and may result in costs and penalties.

        We are subject to a variety of federal, state and local laws and regulations relating to the environment, health and safety, labor and employment and taxation, among others. These laws and

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regulations are complex, change frequently and have tended to become more stringent over time. Failure to comply with these laws and regulations may result in a variety of administrative, civil and criminal enforcement measures, including assessment of monetary penalties and the imposition of remedial requirements. From time to time, as part of the regular overall evaluation of our operations, including newly acquired operations, we may be subject to compliance audits by regulatory authorities. In addition, any failure to comply with regulations related to the government procurement process at the federal, state or local level or restrictions on political activities and lobbying may result in administrative or financial penalties including being barred from providing services to governmental entities, which accounted for approximately two-thirds of our revenues from 2006 through 2008.

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

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

        In August 2008, we acquired our 70% interest in DCE. In April 2009, DCE entered into a 15-year gas sale agreement with Shell for the sale to Shell of specified levels of biomethane produced by DCE's landfill gas processing facility. However, there is no guarantee that DCE will be able to produce or sell up to the maximum volumes called for under the agreement. DCE's ability to produce such volumes of biomethane depends on a number of factors beyond DCE's control, including but not limited to the availability and composition of the landfill gas that is collected, successful permitting, the impact of operation of the landfill by the City of Dallas and the reliability of the processing facility's critical equipment. The DCE facility is subject to periods of reduced production or non-production due to upgrades, maintenance, repairs and other factors. For example, as part of an operational upgrade in March 2009, the facility was shut down for approximately one month. More recently, on June 12, 2009, the facility was taken offline for repairs that were completed on July 2, 2009. Future operational upgrades or complications in the operations of the facility could require additional shut downs, and accordingly, DCE's revenues may fluctuate from quarter to quarter.

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

        Our quarterly results of operations have historically experienced significant fluctuations. Our net losses were approximately $0.9 million, $3.6 million, $1.5 million, $2.9 million, $5.4 million, $3.2 million, $12.1 million, $23.7 million, $6.5 million and $6.4 million for the three months ended March 31, 2007, June 30, 2007, September 30, 2007, December 31, 2007, March 31, 2008, June 30, 2008, September 30, 2008, December 31, 2008, March 31, 2009 and June 30, 2009, respectively. Our quarterly results may fluctuate significantly as a result of a variety of factors, many of which are beyond our control. If our quarterly results of operations fall below the expectations of securities analysts or investors, the price of our common stock could decline substantially. Fluctuations in our quarterly results of operations may be due to a number of factors, including, but not limited to: our ability to increase sales to existing customers and attract new customers, the addition or loss of large customers, construction cost overruns, downtime at our facilities (including the recent shutdowns in March and June 2009 of DCE's landfill gas processing facility), the amount and timing of operating costs, unanticipated expenses, capital expenditures related to the maintenance and expansion of our business, operations and infrastructure, changes in the price of natural gas, changes in the prices of CNG and LNG relative to

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gasoline and diesel, changes in our pricing policies or those of our competitors, the costs related to the acquisition of assets or businesses, regulatory changes, expenses for ballot initiatives that could impact our business and geopolitical events such as war, threat of war or terrorist actions. Investors in our stock should not rely on the results of one quarter as an indication of future performance as our quarterly revenues and results of operations may vary significantly in the future. Therefore, period-to-period comparisons of our operating results may not be meaningful.

The future price of our common stock or the offering price of our common stock in future offerings could result in a reduction of the exercise price of our Series I warrants and result in dilution of our common stock.

        We issued Series I warrants to purchase up to 3,314,394 shares of our common stock in connection with our registered direct offering completed in November 2008. These warrants contain provisions that require an adjustment in the exercise price of the Series I warrants in the event that we price any offering of common stock at a price below the current exercise price, which is $12.68 per share after our follow-on equity offering we completed on July 1, 2009.

        In addition, on November 3, 2009 and November 3, 2010, the exercise price per share of the Series I warrants could be reduced if the then current market price is sufficiently less than the then exercise price for the Series I warrants. In such an instance, the exercise price would reset to 120% of the then current market price so long as such resulting price is less than the then exercise price. If the Series I warrants are exercised, it would be dilutive to our stockholders by increasing the number of shares of our common stock outstanding, which would reduce our earnings per share.

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

        If our stockholders sell, or indicate an intention to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline. At August 5, 2009, 59,692,712 shares of our common stock were outstanding. The 11,500,000 shares sold in our initial public offering, the 4,419,192 shares of common stock and the 3,314,394 shares of common stock subject to outstanding warrants sold in our registered direct offering that closed on November 3, 2008, and the 9,430,000 shares of our common stock sold in our common stock offering that closed July 1, 2009 are freely tradable without restriction or further registration under federal securities laws unless purchased by our affiliates. Shares held by non-affiliates for more than six months may generally be sold without restriction, other than a current public information requirement, and may be sold freely without any restrictions after one year. All other outstanding shares of common stock may be sold under Rule 144 under the Securities Act, subject to applicable restrictions.

        In addition, as of June 30, 2009, there were 9,259,052 shares underlying outstanding options and 18,314,394 shares underlying outstanding warrants (including the 3,314,394 Series I warrant shares sold in our registered direct offering which closed on November 3, 2008). All shares subject to outstanding options and warrants are eligible for sale in the public market to the extent permitted by the provisions of various option and warrant agreements and Rule 144. If these additional shares are sold, or if it is perceived that they will be sold in the public market, the trading price of our stock could decline.

        Further, as of June 30, 2009, 16,539,720 shares of our stock held by our co-founder and board member T. Boone Pickens are subject to a pledge agreement with a bank. Should the bank be forced to sell the shares subject to the pledge, the trading price of our stock could also decline. On December 1, 2008, Warren I. Mitchell, our Chairman of the Board, entered into a Rule 10b5-1 Sales Plan with a broker to sell shares of our common stock that may be acquired upon the exercise of stock options. Under the plan, the broker may sell up to 2,000 shares of common stock each month, beginning in January 2009, provided that the price per underlying share is at or above $10.00 on the Nasdaq Global

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Market. All sales of common stock under the plan will be reported through appropriate filings with the SEC.

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

        As of June 30, 2009 and August 7, 2009, Boone Pickens and affiliates (including Madeleine Pickens, his wife) beneficially owned in the aggregate approximately 53.9% and 46.5%, respectively, of the outstanding shares of our common stock, inclusive of the 15,000,000 shares underlying a warrant held by Mr. Pickens. As a result, Mr. Pickens will be able to influence or control matters requiring approval by our stockholders, including the election of directors and the approval of mergers, acquisitions or other extraordinary transactions. Mr. Pickens may also have interests that differ from yours and may vote in a way with which you disagree and which may be adverse to your interests. This concentration of ownership may have the effect of delaying, preventing or deterring a change of control of our company, could deprive our stockholders of an opportunity to receive a premium for their stock as part of a sale of our company, and might ultimately affect the market price of our stock. Conversely, this concentration may facilitate a change in control at a time when you and other investors may prefer not to sell.

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

        None.

Item 3.—Defaults upon Senior Securities

        None.

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

        Our annual meeting of stockholders was held on May 12, 2009. The stockholders elected seven members to our Board of Directors to serve until the next annual meeting of stockholders or until their respective successors have been duly elected and qualified. In addition, the stockholders ratified the appointment of KPMG LLP as our independent registered public accounting firm for the fiscal year ending December 31, 2009 and approved an amendment to our Amended and Restated 2006 Equity Incentive Plan to increase the number of shares of our common stock authorized for issuance under the plan from 9,390,500 shares to 10,890,500 shares.

        The number of shares voting as to the above issues is set forth below.

 
  Votes  
1.    Election of Directors:
  For   Withheld  

Andrew J. Littlefair

    42,982,024     568,570  

Warren I. Mitchell

    41,394,146     2,156,448  

John S. Herrington

    41,425,944     2,124,650  

James C. Miller III

    42,944,268     605,326  

Boone Pickens

    43,012,305     538,209  

Kenneth M. Socha

    42,077,038     1,476,556  

Vincent C. Taormina

    42,964,929     585,665  

2.    The stockholders ratified the selection of KPMG LLP as our independent registered public accounting firm for the fiscal year ending December 31, 2009, with voting as follows: 43,134,761 for; 289,674 against; and 126,158 abstain.

3.    The stockholders approved an amendment to our Amended and Restated 2006 Equity Incentive Plan to increase the number of shares of our common stock authorized for issuance under the plan from 9,390,500 shares to 10,890,500 shares, with voting as follows: 22,802,423 for; 4,975,540 against; 77,442 abstain; and 15,358,542 broker non-votes.

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Item 5.—Other Information

        None.

Item 6.—Exhibits

(a)
Exhibits
  2.3   Purchase and Sale Agreement dated as of May 7, 2009 by and between Clean Energy and Exterran Energy Solutions, L.P. (incorporated by reference to Form 8-K, filed on May 11, 2009).

 

10.2

 

Clean Energy Fuels Corp. 2006 Amended and Restated Equity Incentive Plan, as amended on May 12, 2009 (incorporated by reference to Form 8-K, filed on May 19, 2009).

 

10.50

 

Base Contract for Sale and Purchase of Natural Gas between Shell Energy North America (US), LP and Dallas Clean Energy, LLC.*†

 

10.51

 

First Amendment to Loan Agreement among Clean Energy and Dallas Clean Energy, 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.*

*
Filed herewith.

Confidential treatment has been requested for certain portions of Exhibit 10.50 under CFR §§ 230.24b-2 and 200.80(b)(4).

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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: August 10, 2009

 

By:

 

/s/ RICHARD R. WHEELER

        Richard R. Wheeler
        Chief Financial Officer
(Principal financial officer and duly authorized
to sign on behalf of the registrant)

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Exhibit 10.50

    TRANSACTION CONFIRMATION
FOR IMMEDIATE DELIVERY
  EXHIBIT A
Shell Energy North America (US), L.P.   Date: April 3, 2009
Transaction Confirmation #:                                      

This Transaction Confirmation is subject to the Base Contract between Seller and Buyer dated March 30, 2009. The terms of this Transaction Confirmation shall be binding upon execution by the parties.

SELLER:
Dallas Clean Energy, LLC ("DCE")
c/o Cambrian Energy Management LLC
624 South Grand Avenue, Suite 2420
Los Angeles, CA 90017-3325
Attn: Evan G. Williams
Phone: 213.628.8312
Fax: 213.488.9890
With copies of notices to:
Clean Energy
3020 Old Ranch Parkway, Suite 200
Seal Beach, CA 90740
Phone: 562-493-2804
Fax: 562-493-4532
Attn: General Counsel
Base Contract No.                                      
Transporter:                                      
Transporter Contract No.:                          
  BUYER:
Shell Energy North America (US), L.P. ("Shell Energy")
909 Fannin, Plaza Level One
Houston, Texas 77010
Attn: Contract Administration
Phone: 713.767.5400
Fax: 713.265.2171
Base Contract No. 010-NG-BS-15195
Transporter:                                      
Transporter Contract Number:                                      

Contract Price: See Contract Price below under "Special Conditions"

Delivery Period: Begin:     April 4, 2009                         End:     March 31, 2024

Performance Obligation and Contract Quantity:  Subject to the Special Conditions set forth below Buyer shall purchase all gas produced from the Project for each year of the Delivery Period up to the MDV (as defined below):

Firm (Fixed Quantity):   Firm (Variable Quantity):X   Interruptible:
    0     MMBtus/day       MMBtus/day

 

 

o EFP

 

 

 

 

SEE SELLER'S AND BUYER'S FIRM OBLIGATIONS below

Delivery Point(s): Sweetie Peck on EPNG

Buyer and Seller agree that Seller is solely responsible for all transportation and related pipeline charges for the transportation of gas from the Project to the Delivery Point.

Special Conditions

Definitions and General Terms and Conditions

"EPNG" means El Paso Natural Gas Pipeline.

Gas Nominations:  Seller agrees to nominate RNG volumes by 9:00 a.m. PPT on the business day prior to any weekday and on or before 9:00 a.m. PPT on Friday for delivery on Saturday, Sunday and Monday.

"Lender" means any person or entity providing at any time debt or lease financing to Seller and/or Seller's members, corporate affiliates, successors and assigns for any business purpose related to the Project and secured in part, directly or indirectly, by Seller's interest in one or both of the Base Contract and the Transaction Confirmation.

 
   
Copyright © 2002 North American Energy Standards Board, Inc.   NAESB Standard 6.3.1
All Rights Reserved   April 19, 2002
***
Confidential portions of this document have been redacted and filed separately with the Securities and Exchange Commission.

1


Maximum Daily Volume ("MDV"):   MDV is the maximum amount of RNG produced by the Project that will be sold to Buyer and the amount of transportation capacity that will be deducted from the fixed price. MDV shall be equal to the volumes set forth in the Table below. Notwithstanding anything contained herein to the contrary, until the successful permitting, construction and commencement of commercial operation of an expansion to the existing gas processing facility that is part of the Project to at least 15 million standard cubic feet per day inlet capacity of raw landfill gas, the MDV shall be equal to 4500 MMBtu/day; provided however, that no increases from the 4500 MMBtu/day MDV will be effective unless Seller has given Buyer eight Months' prior written notice of the expected commencement date of the expansion.

Buyer and Seller agree that irrespective of actual gas volumes delivered under this Transaction Confirmation that Seller is fully responsible for all EPNG Firm Monthly Reservation Charges for the MDV capacity for the entire Delivery Period to the extent that such EPNG capacity has been contracted by Buyer.

Seller's and Buyer's Firm Obligation:  Seller agrees to deliver to Buyer and Buyer agrees to purchase, on a daily Firm basis, all RNG produced from the Project up to the MDV, except for (a) and (b) below.

Delivery
  (MDV)

April 2009 through September 2010

  4500 MMBtu per day

October 2010 to December 2010

  5200 MMBtu per day

Calendar Year 2011

  5300 MMBtu per day

Calendar Year 2012

  5400 MMBtu per day

Calendar Year 2013

  5300 MMBtu per day

Calendar Year 2014

  5300 MMBtu per day

Calendar Year 2015 to 2018

  5000 MMBtu per day

Calendar Year 2019 to March 2024

  6000 MMBtu per day

In the event the actual RNG volumes for an entire year average less than 50% of the MDV, then upon receipt of written request from Buyer, Buyer and Seller will meet for the purpose of discussing whether it is appropriate to adjust the MDV.

"PPT" mean Pacific Prevailing Time.

"Project" means Seller's McCommas Bluff Landfill Gas Processing Facility in Dallas, Texas.

"Renewable Natural Gas" ("RNG") means Gas production from the Project that:

***
Confidential portions of this document have been redacted and filed separately with the Securities and Exchange Commission.

2


"Surplus Daily Capacity" ( "SDC" ) means any excess unutilized volumes of Buyer's EPNG transportation capacity resulting from the difference between the applicable MDV and the gas volumes actually nominated for a given gas day.

Term:  Buyer shall have the exclusive right for the first 45 days of the last 60 day period of the initial Delivery Period to negotiate an extension of this Transaction at terms mutually agreeable to Buyer and Seller if at that end of the Delivery Period DCE has at least 5 years remaining on the term of the Landfill Gas Lease with the City of Dallas that is part of the Project that is not subject to any right of termination, for convenience or otherwise, in favor of the City of Dallas.

Contract Price:

As part of the pricing formulas and volume terms and conditions below the Fixed Price component is:

[***] per MMBtu for April to December 2009
[***] per MMBtu for January to December 2010
[***] per MMBtu for January 2011 to March 2024

Contract Price for actual gas volumes delivered by Seller to Buyer:

Buyer shall pay Seller the Fixed Price per MMBtu multiplied by the actual volume of MMBtus delivered less

the EPNG Firm Monthly Reservation Charge multiplied by the MDV and less

the EPNG variable charges and a Determined Value for fuel losses* multiplied by the actual daily volumes.

*
For purposes hereof, the Determined Value for fuel losses shall be equal to a "monetized value" for fuel losses equal to the percentage set forth in the then applicable tariff of EPNG of actual daily volumes measured each day in MMBtus for fuel losses multiplied by the Gas Daily Permian Basin midpoint price.

During the Delivery period hereof, upon Seller's request, Buyer will convert the fuel formula above from a "monetized value" to an "in-kind" process based on the applicable EPNG tariff, (a reduction in volume equivalent to the fuel charges), if there are no regulatory limitations to such conversion.

As a 2009 daily illustrative example on a day with actual volumes delivered to Buyer of 3100 MMBtus, assuming EPNG charges are the following:

FIRM TRANSPORTATION

***
Confidential portions of this document have been redacted and filed separately with the Securities and Exchange Commission.

3


Monthly Reservation   [***]
Base Usage*   [***]
Surcharges*   [***]
TOTAL   [***]

FUEL CHARGES*

*
Only paid for volume flowed. ([***] of 3100 MMBtus assuming [***]/MMBtu
As Gas Daily Permian Basin Midpoint price/MMbtu)  
Price Payable or Firm
Transportation
Deduction Item
Description
  Price or Charge Per
MMBtu
  MMBtus to which
Price or Charge
Applies
  Aggregate Price or
Charge
 

Gross Revenues

                 

Applicable Purchase Price for RNG

  [***]     3,100     [***]  

Firm Transportation EPNG Tariff Deductions

                 

Monthly Reservation Charge (Based on full capacity reserved in MMBtus)

  [***]     4,500     [***]  

Base Usage (Based on actual volume flowed in MMBtus)

  [***]     3,100     [***]  

Surcharges (Based on actual volume flowed in MMBtus)

  [***]     3,100     [***]  

Fuel Charges (Based on value of 2.69% of actual volume flowed in MMBtus @ Gas Daily Permina Basin Midpoint price/MMBtu—assumed at $5.00/MMbtu for illustration)

  [***]
Assumed Midpoint Price
for Purposes of
Illustration
    [***] × 3,100 = [***]     [***]  

Net Price Payable After EPNG Firm Transportation Charges for Day

              [***]  

Optimization of Surplus Daily Capacity and Pricing:

Buyer shall provide optimization services to Seller for the Surplus Daily Capacity. Buyer and Seller shall share in equal positive values extracted from this optimization calculated as follows:

"Market Spread" means Gas Daily PG&E South midpoint minus Gas Daily El Paso Permian Basin midpoint

"EPNG Variable Charges" consist of Base Usage, Surcharges and Fuel

If Market Spread is greater than EPNG Variable Charges then:

Buyer shall credit to Seller Fifty percent (50%) of the difference between Market Spread less EPNG Variable Charges; multiplied by the Surplus Daily Capacity.

As a 2009 daily illustrative example, assuming that the Market Spread is $1.00/MMBtu and the SDC is 200 MMBtu consistent with the pricing example above and EPNG Variable Charges are the following:

***
Confidential portions of this document have been redacted and filed separately with the Securities and Exchange Commission.

4


El PASO Variable Charges

Base Usage*   [***]
Surcharges*   [***]
Fuel (example using $5/MMBtu)   [***] of actual volume in MMBtus
TOTAL INCREMENTAL BEFORE FUEL   [***]

50% × (($1.00 × 200) - (([***] × 200) + ([***] × 200 × [***]))) = [***] due by Buyer to Seller for day.

Damages for Intra-Day Volume Changes.

The following damages shall constitute "Alternative Damages" to be effective in lieu of Section 3.2 of the Base Contract for the purposes of this Confirmation:

Seller shall be responsible for costs to Buyer associated with intra-day volume changes according to the following formula:

If Actual Volume Produced is greater than Nominated Volume, then (El Paso Permian Basin midpoint minus El Paso Permian Basin Absolute Low) * (Actual Volume Produced minus Nominated Volume)

If Actual Volume Produced is less than Nominated Volume (El Paso Permian Basin Absolute High minus El Paso Permian Basin midpoint) * (Nominated Volume minus Actual Volume Produced)

As an illustrative example, assuming the following Gas Daily prices on any one day:

Permian
Abs High
  Permian
Abs Low
  Permian
Midpoint
  Volume
Nominated
 
  6.78     6.56     6.64     1,000  

If Actual Volume Produced was 1,500 MMBtu/day, then (6.64 - 6.56) * (1,500 - 1,000) = $40 due from Seller to Buyer for the day.

If Actual Volume Produced was 500 MMBtu/day, then (6.78 - 6.64) * (1,000 - 500) = $70 due from Seller to Buyer for the day.

Agency Agreement on Atmos Pipeline.  Buyer agrees to be Seller's agent for purposes of scheduling and invoicing on the Atmos Pipeline and gathering system. Imbalances on Atmos Pipeline shall remain the financial responsibility of Seller but Buyer agrees to act on Seller's behalf to minimize any adverse impacts to the extent commercially and reasonably possible. The Parties agree to work out a mutually agreeable arrangement on credit for associated Atmos charges. For example, Seller may post a deposit of one month's average Atmos Pipeline charges with Buyer in order to enable Buyer to pay Atmos on Seller's behalf. Such charges shall then be deducted from Seller's monthly revenue.

Early Termination of this Transaction Confirmation:

***
Confidential portions of this document have been redacted and filed separately with the Securities and Exchange Commission.

5


Consent to Collateral Assignment:

Subject to the provisions hereunder, Seller shall have the right to assign this Agreement as collateral for any financing or refinancing of the gas processing facility located at the McCommas Bluff Landfill in Dallas, Texas and any replacements or expansions thereto, the collection system and any related equipment and contractual rights (the "Project").

In connection with any financing or refinancing of the Project by Seller, Buyer shall in good faith work with Seller and Lender to agree upon a consent to collateral assignment of this Agreement ("Collateral Assignment Agreement"); provided, however, if Seller and Lender are unable to reach agreement on the terms of such Collateral Assignment Agreement within sixty (60) days from the commencement of negotiations thereon, Seller shall have the right to terminate this Agreement upon the giving of written notice to Buyer.

The Collateral Assignment Agreement shall be in form and substance agreed to by Buyer, Seller and Lender, and shall include, among others, the following provisions:

***
Confidential portions of this document have been redacted and filed separately with the Securities and Exchange Commission.

6


Seller:   Dallas Clean Energy, LLC   Buyer:   Shell Energy North America (US), L.P.
    By: Cambrian Energy Management LLC, its Manager   By:   /s/ Beth Bowman

By:   /s/ Evan G. Williams

  Title:   Sr. Vice President
Title:   Manager   Date:   March 30, 2009

Date:   March 30, 2009

       
***
Confidential portions of this document have been redacted and filed separately with the Securities and Exchange Commission.

7


Base Contract for Sale and Purchase of Natural Gas

This Base Contract is entered into as of the following date: March 30, 2009. The parties to this Base Contract are the following:

Shell Energy North America (US), L.P.,
a Delaware limited partnership
Duns Number: [***]                                    
Contract Number: [***]                                    
U.S. Federal Tax ID Number: [***]                        
  and   Dallas Clean Energy, LLC
a Delaware limited liability company
Duns Number:                                     
Contract Number:                                     
U.S. Federal Tax ID Number             [***]            

Notices:
4445 Eastgate Mall, Suite 100, San Diego, CA 92121
Attn: Contracts North America
Phone: (858) 320-1500                 Fax: (858) 320-1550
      
Confirmations:
909 Fannin, Plaza Level 1, Houston, TX 77010
Attn: Contracts North America
Phone: (713) 230-7505                 Fax: (713) 265-2171
     
Invoices and Payments:
909 Fannin, Plaza Level 1, Houston, TX 77010
Attn: Gas Accounting
Phone: (713) 767-5400                 Fax: (713) 767-5445
      
Wire Transfer or ACH Numbers (if applicable):
BANK: [***]                                    
ABA: [***]                                    
ACCT: [***]                                    
Other Details:                                     

 

 

 

624 So. Grand Ave. #2420, Los Angeles, CA 90017-3325
Attn:  Evan G. Williams—Cambrian Energy Management LLC
Phone: (213) 628-8312                 Fax: (213) 488-9890
      
624 So. Grand Ave. #2420, Los Angeles. CA 90017-3325
Attn: Evan G. Williams—Cambrian Enemy Management LLC
Phone: (213) 628-8312                 Fax: (213) 488-9890
     
624 So. Grand Ave. #2420, Los Angeles, CA 90017-3325
Attn: Rhys Williams—Cambrian Energy Management LLC
Phone: (213) 628-8312                 Fax: (213) 488-9890
      
BANK: [***]                                    
ABA: [***]                                    
ACCT: [***]                                    
Other Details:                                     

This Base Contract incorporates by reference for all purposes the General Terms and Conditions for Sale and Purchase of Natural Gas published by the North American Energy Standards Board. The parties hereby agree to the following provisions offered in said General Terms and Conditions. In the event the parties fail to check a box, the specified default provision shall apply. Select only one box from each section:

Section 1.2
Transaction Procedure
  • Oral (default)
o  Written
  Section 7.2
Payment Date
  25 th Day of Month following Month of delivery (default)
o                            Day of Month following Month of delivery

Section 2.5
Confirm Deadline

 

• 2 Business Days after receipt (default)
o                            Business Days after receipt

 

Section 7.2
Method of Payment

 

• Wire Transfer (default)
o  Automated Clearinghouse Credit (ACH)
o  Check

Section 2.6
Confirming Party

 

o  Seller (default)
o  Buyer
Shell Energy North America (US), L.P.

 

Section 7.7
Netting

 

• Netting applies (default)
o  Netting does not apply

Section 3.2
Performance Obligation

 

• Cover Standard (default)
o  Spot Price Standard

 

Section 10.3.1
Early Termination Damages

 

• Early Termination Damages Apply (default)
o  Early Termination Damages Do Not Apply

Note: The following Spot Price Publication applies to both of the immediately preceding.

 

Section 10.3.2
Other Agreement Setoffs

 

• Other Agreement Setoffs Apply (default)
o  Other Agreement Setoffs Do Not Apply

Section 2.26
Spot Price Publication

 

• Gas Daily Midpoint (default)
o                                        

 

Section 14.5
Choice of Law

 

                        Texas                         

Section 6
Taxes

 

• Buyer Pays At and After Delivery Point (default)
o  Seller Pays Before and At Delivery Point

 

Section 14.10
Confidentiality

 

• Confidentiality applies (default)
o  Confidentiality does not apply

Special Provisions Number of sheets attached: One (1)
o  
Addendum(s): None

 

 

 

 
***
Confidential portions of this document have been redacted and filed separately with the Securities and Exchange Commission.

IN WITNESS WHEREOF, the parties hereto have executed this Base Contract in duplicate.

SHELL ENERGY NORTH AMERICA (US), L.P.
Party Name
  DALLAS CLEAN ENERGY, LLC
Party Name
By Cambrian Energy Management LLC, Manager

By:

 

/s/ Beth Bowman


 

By:

 

/s/ Evan G. Williams
Name:   Beth Bowman

  Name:   Evan G. Williams
Title:   Sr. Vice President

  Title:   Manager

2



General Terms and Conditions
Base Contract for Sale and Purchase of Natural Gas

SECTION 1.     PURPOSE AND PROCEDURES     

1.1.  These General Terms and Conditions are intended to facilitate purchase and sale transactions of Gas on a Firm or Interruptible basis. "Buyer" refers to the party receiving Gas and "Seller" refers to the party delivering Gas. The entire agreement between the parties shall be the Contract as defined in Section 2.7.

The parties have selected either the "Oral Transaction Procedure" or the "Written Transaction Procedure" as indicated on the Base Contract.

Oral Transaction Procedure:

1.2.  The parties will use the following Transaction Confirmation procedure. Any Gas purchase and sale transaction may be effectuated in an EDI transmission or telephone conversation with the offer and acceptance constituting the agreement of the parties. The parties shall be legally bound from the time they so agree to transaction terms and may each rely thereon. Any such transaction shall be considered a "writing" and to have been "signed". Notwithstanding the foregoing sentence, the parties agree that Confirming Party shall, and the other party may, confirm a telephonic transaction by sending the other party a Transaction Confirmation by facsimile, EDI or mutually agreeable electronic means within three Business Days of a transaction covered by this Section 1.2 (Oral Transaction Procedure) provided that the failure to send a Transaction Confirmation shall not invalidate the oral agreement of the parties. Confirming Party adopts its confirming letterhead, or the like, as its signature on any Transaction Confirmation as the identification and authentication of Confirming Party. If the Transaction Confirmation contains any provisions other than those relating to the commercial terms of the transaction (i.e., price, quantity, performance obligation, delivery point, period of delivery and/or transportation conditions), which modify or supplement the Base Contract or General Terms and Conditions of this Contract (e.g., arbitration or additional representations and warranties), such provisions shall not be deemed to be accepted pursuant to Section 1.3 but must be expressly agreed to by both parties; provided that the foregoing shall not invalidate any transaction agreed to by the parties.

Written Transaction Procedure:

1.2.  The parties will use the following Transaction Confirmation procedure. Should the parties come to an agreement regarding a Gas purchase and sale transaction for a particular Delivery Period, the Confirming Party shall, and the other party may, record that agreement on a Transaction Confirmation and communicate such Transaction Confirmation by facsimile, EDI or mutually agreeable electronic means, to the other party by the close of the Business Day following the date of agreement. The parties acknowledge that their agreement will not be binding until the exchange of nonconflicting Transaction Confirmations or the passage of the Confirm Deadline without objection from the receiving party, as provided in Section 1.3.

1.3.  If a sending party's Transaction Confirmation is materially different from the receiving party's understanding of the agreement referred to in Section 1.2, such receiving party shall notify the sending party via facsimile, EDI or mutually agreeable electronic means by the Confirm Deadline, unless such receiving party has previously sent a Transaction Confirmation to the sending party. The failure of the receiving party to so notify the sending party in writing by the Confirm Deadline constitutes the receiving party's agreement to the terms of the transaction described in the sending party's Transaction Confirmation. If there are any material differences between timely sent Transaction Confirmations governing the same transaction, then neither Transaction Confirmation shall be binding until or unless such differences are resolved including the use of any evidence that clearly resolves the differences in the Transaction Confirmations. In the event of a conflict among the terms of (i) a binding Transaction Confirmation pursuant to Section 1.2, (ii) the oral agreement of the parties which may be evidenced by a recorded conversation, where the parties have selected the Oral Transaction Procedure of the Base Contract, (iii) the Base Contract, and (iv) these General Terms and Conditions, the terms of the documents shall govern in the priority listed In this sentence.

1.4.  The parties agree that each party may electronically record all telephone conversations with respect to this Contract between their respective employees, without any special or further notice to the other party. Each party shall obtain any necessary consent of its agents and employees to such recording. Where the parties have selected the Oral Transaction Procedure in Section 1.2 of the Base Contract, the parties agree not to contest the validity or enforceability of telephonic recordings entered into in accordance with the requirements of this Base Contract. However, nothing herein shall be construed as a waiver of any objection to the admissibility of such evidence.

3


SECTION 2.     DEFINITIONS     

The terms set forth below shall have the meaning ascribed to them below. Other terms are also defined elsewhere in the Contract and shall have the meanings ascribed to them herein.

2.1.  "Alternative Damages" shall mean such damages, expressed in dollars or dollars per MMBtu, as the parties shall agree upon in the Transaction Confirmation, in the event either Seller or Buyer fails to perform a Firm obligation to deliver Gas in the case of Seller or to receive Gas in the case of Buyer.

2.2.  "Base Contract" shall mean a contract executed by the parties that incorporates these General Terms and Conditions by reference; that specifies the agreed selections of provisions contained herein; and that sets forth other information required herein and any Special Provisions and addendum(s) as identified on page one.

2.3.  "British thermal unit" or "Btu" shall mean the International BTU, which is also called the Btu (IT).

2.4.  "Business Day" shall mean any day except Saturday, Sunday or Federal Reserve Bank holidays.

2.5.  "Confirm Deadline" shall mean 5:00 p.m. in the receiving party's time zone on the second Business Day following the Day a Transaction Confirmation is received or, if applicable, on the Business Day agreed to by the parties in the Base Contract; provided, if the Transaction Confirmation is time stamped after 5:00 p.m. in the receiving party's time zone, it shall be deemed received at the opening of the next Business Day.

2.6.  "Confirming Party" shall mean the party designated in the Base Contract to prepare and forward Transaction Confirmations to the other party.

2.7.  "Contract" shall mean the legally-binding relationship established by (i) the Base Contract, (ii) any and all binding Transaction Confirmations and (iii) where the parties have selected the Oral Transaction Procedure in Section 1.2 of the Base Contract, any and all transactions that the parties have entered into through an EDI transmission or by telephone, but that have not been confirmed in a binding Transaction Confirmation.

2.8.  "Contract Price" shall mean the amount expressed in U.S. Dollars per MMBtu to be paid by Buyer to Seller for the purchase of Gas as agreed to by the parties in a transaction.

2.9.  "Contract Quantity" shall mean the quantity of Gas to be delivered and taken as agreed to by the parties in a transaction.

2.10.  "Cover Standard", as referred to in Section 3.2, shall mean that if there is an unexcused failure to take or deliver any quantity of Gas pursuant to this Contract, then the performing party shall use commercially reasonable efforts to (i) if Buyer is the performing party, obtain Gas, (or an alternate fuel if elected by Buyer and replacement Gas is not available), or (ii) if Seller is the performing party, sell Gas, in either case, at a price reasonable for the delivery or production area, as applicable, consistent with: the amount of notice provided by the nonperforming party; the immediacy of the Buyer's Gas consumption needs or Seller's Gas sales requirements, as applicable; the quantities involved; and the anticipated length of failure by the nonperforming party.

2.11.  "Credit Support Obligation(s)" shall mean any obligation(s) to provide or establish credit support for, or on behalf of, a party to this Contract such as an irrevocable standby letter of credit, a margin agreement, a prepayment, a security interest in an asset, a performance bond, guaranty, or other good and sufficient security of a continuing nature.

2.12.  "Day" shall mean a period of 24 consecutive hours, coextensive with a "day" as defined by the Receiving Transporter in a particular transaction.

2.13.  "Delivery Period" shall be the period during which deliveries are to be made as agreed to by the parties in a transaction.

2.14.  "Delivery Point(s)" shall mean such point(s) as are agreed to by the parties in a transaction.

2.15.  "EDI" shall mean an electronic data interchange pursuant to an agreement entered into by the parties, specifically relating to the communication of Transaction Confirmations under this Contract.

2.16.  "EFP" shall mean the purchase, sale or exchange of natural Gas as the "physical" side of an exchange for physical transaction involving gas futures contracts. EFP shall incorporate the meaning and remedies of "Firm", provided that a party's excuse for nonperformance of its obligations to deliver or receive Gas will be governed by the rules of the relevant futures exchange regulated under the Commodity Exchange Act.

2.17.  "Firm" shall mean that either party may interrupt its performance without liability only to the extent that such performance is prevented for reasons of Force Majeure; provided, however, that during Force Majeure interruptions, the party invoking Force Majeure may be responsible for any Imbalance Charges as set forth in Section 4.3 related to its interruption after the nomination is made to the Transporter and until the change in deliveries and/or receipts is confirmed by the Transporter.

4


2.18.  "Gas" shall mean any mixture of hydrocarbons and noncombustible gases in a gaseous state consisting primarily of methane.

2.19.  "Imbalance Charges" shall mean any fees, penalties, costs or charges (in cash or in kind) assessed by a Transporter for failure to satisfy the Transporter's balance and/or nomination requirements.

2.20.  "Interruptible" shall mean that either party may interrupt its performance at any time for any reason, whether or not caused by an event of Force Majeure, with no liability, except such interrupting party may be responsible for any lmbalance Charges as set forth in Section 4.3 related to its Interruption after the nomination is made to the Transporter and until the change in deliveries and/or receipts is confirmed by Transporter.

2.21.  "MMBtu" shall mean one million British thermal units, which is equivalent to one dekatherm.

2.22.  "Month" shall mean the period beginning on the first Day of the calendar month and ending immediately prior to the commencement of the first Day of the next calendar month.

2.23.  "Payment Date" shall mean a date, as indicated on the Base Contract, on or before which payment is due Seller for Gas received by Buyer in the previous Month.

2.24.  "Receiving Transporter" shall mean the Transporter receiving Gas at a Delivery Point, or absent such receiving Transporter, the Transporter delivering Gas at a Delivery Point.

2.25.  "Scheduled Gas" shall mean the quantity of Gas confirmed by Transporter(s) for movement, transportation or management.

2.26.  "Spot Price" as referred to in Section 3.2 shall mean the price listed in the publication indicated on the Base Contract, under the listing applicable to the geographic location closest in proximity to the Delivery Point(s) for the relevant Day; provided, if there is no single price published for such location for such Day, but there is published a range of prices, then the Spot Price shall be the average of such high and low prices. If no price or range of prices is published for such Day, then the Spot Price shall be the average of the following: (i) the price (determined as stated above) for the first Day for which a price or range of prices is published that next precedes the relevant Day; and (ii) the price (determined as stated above) for the first Day for which a price or range of prices is published that next follows the relevant Day.

2.27.  "Transaction Confirmation" shall mean a document, similar to the form of Exhibit A, setting forth the terms of a transaction formed pursuant to Section 1 for a particular Delivery Period.

2.28.  "Termination Option" shall mean the option of either party to terminate a transaction in the event that the other party fails to perform a Firm obligation to deliver Gas in the case of Seller or to receive Gas in the case of Buyer for a designated number of days during a period as specified on the applicable Transaction Confirmation.

2.29.  "Transporter(s)" shall mean all Gas gathering or pipeline companies, or local distribution companies, acting in the capacity of a transporter, transporting Gas for Seller or Buyer upstream or downstream, respectively, of the Delivery Point pursuant to a particular transaction.

SECTION 3.     PERFORMANCE OBLIGATION     

3.1.  Seller agrees to sell and deliver, and Buyer agrees to receive and purchase, the Contract Quantity for a particular transaction in accordance with the terms of the Contract. Sales and purchases will be on a Firm or Interruptible basis, as agreed to by the parties in a transaction.

The parties have selected either the "Cover Standard" or the "Spot Price Standard" as indicated on the Base Contract.

Cover Standard:

3.2.  The sole and exclusive remedy of the parties in the event of a breach of a Firm obligation to deliver or receive Gas shall be recovery of the following: (i) in the event of a breach by Seller on any Day(s), payment by Seller to Buyer in an amount equal to the positive difference, if any, between the purchase price paid by Buyer utilizing the Cover Standard and the Contract Price, adjusted for commercially reasonable differences in transportation costs to or from the Delivery Point(s), multiplied by the difference between the Contract Quantity and the quantity actually delivered by Seller for such Day(s); or (ii) in the event of a breach by Buyer on any Day(s), payment by Buyer to Seller in the amount equal to the positive difference, if any, between the Contract Price and the price received by Seller utilizing the Cover Standard for the resale of such Gas, adjusted for commercially reasonable differences in transportation costs to or from the Delivery Point(s), multiplied by the difference between the Contract Quantity and the quantity actually taken by Buyer for such Day(s); or (iii) in the event that Buyer has used commercially reasonable efforts to replace the Gas or Seller has used commercially reasonable efforts to sell the Gas to a third party, and no such replacement or sale is available, then the sole and exclusive remedy of the performing party shall be any unfavorable difference between the Contract Price and the Spot Price, adjusted for such transportation to the applicable Delivery Point, multiplied by the difference between the Contract Quantity and the quantity actually delivered by Seller and received by Buyer for such Day(s). Imbalance Charges shall not be recovered under this Section 3.2, but Seller and/or Buyer shall be responsible for Imbalance Charges, if any, as provided in Section 4.5. The amount of such unfavorable difference shall be payable five Business Days after presentation of the performing party's invoice, which shall set forth the basis upon which such amount was calculated.

5


Spot Price Standard:

3.2.  The sole and exclusive remedy of the parties in the event of a breach of a Firm obligation to deliver or receive Gas shall be recovery of the following: (i) in the event of a breach by Seller on any Day(s), payment by Seller to Buyer in an amount equal to the difference between the Contract Quantity and the actual quantity delivered by Seller and received by Buyer for such Day(s), multiplied by the positive difference, if any, obtained by subtracting the Contract Price from the Spot Price; or (ii) in the event of a breach by Buyer on any Day(s), payment by Buyer to Seller in an amount equal to the difference between the Contract Quantity and the actual quantity delivered by Seller and received by Buyer for such Day(s), multiplied by the positive difference, if any, obtained by subtracting the applicable Spot Price from the Contract Price. Imbalance Charges shall not be recovered under this Section 3.2, but Seller and/or Buyer shall be responsible for Imbalance Charges, if any, as provided in Section 4.3. The amount of such unfavorable difference shall be payable five Business Days after presentation of the performing party's invoice, which shall set forth the basis upon which such amount was calculated.

3.3.  Notwithstanding Section 3.2, the parties may agree to Alternative Damages in a Transaction Confirmation executed in writing by both parties.

3.4.  In addition to Sections 3.2 and 3.3, the parties may provide for a Termination Option in a Transaction Confirmation executed in writing by both parties. The Transaction Confirmation containing the Termination Option will designate the length of nonperformance triggering the Termination Option and the procedures for exercise thereof, how damages for nonperformance will be compensated, and how liquidation costs will be calculated.

SECTION 4.     TRANSPORTATION, NOMINATIONS, AND IMBALANCES     

4.1.  Seller shall have the sole responsibility for transporting the Gas to the Delivery Point(s). Buyer shall have the sole responsibility for transporting the Gas from the Delivery Point(s).

4.2.  The parties shall coordinate their nomination activities, giving sufficient time to meet the deadlines of the affected Transporter(s). Each party shall give the other party timely prior Notice, sufficient to meet the requirements of all Transporter(s) involved in the transaction, of the quantities of Gas to be delivered and purchased each Day. Should either party become aware that actual deliveries at the Delivery Point(s) are greater or lesser than the Scheduled Gas, such party shall promptly notify the other party.

4.3.  The parties shall use commercially reasonable efforts to avoid imposition of any Imbalance Charges. If Buyer or Seller receives an invoice from a Transporter that includes Imbalance Charges, the parties shall determine the validity as well as the cause of such Imbalance Charges. If the Imbalance Charges were incurred as a result of Buyer's receipt of quantities of Gas greater than or less than the Scheduled Gas, then Buyer shall pay for such Imbalance Charges or reimburse Seller for such Imbalance Charges paid by Seller. If the Imbalance Charges were incurred as a result of Seller's delivery of quantities of Gas greater than or less than the Scheduled Gas, then Seller shall pay for such Imbalance Charges or reimburse Buyer for such Imbalance Charges paid by Buyer.

SECTION 5.     QUALITY AND MEASUREMENT     

All Gas delivered by Seller shall meet the pressure, quality and heat content requirements of the Receiving Transporter. The unit of quantity measurement for purposes of this Contract shall be one MMBtu dry. Measurement of Gas quantities hereunder shall be in accordance with the established procedures of the Receiving Transporter.

6


SECTION 6.     TAXES     

The parties have selected either "Buyer Pays At and After Delivery Point" or "Seller Pays Before and At Delivery Point" as indicated on the Base Contract.

Buyer Pays At and After Delivery Point:

Seller shall pay or cause to be paid all taxes, fees, levies, penalties, licenses or charges imposed by any government authority ("Taxes") on or with respect to the Gas prior to the Delivery Point(s). Buyer shall pay or cause to be paid all Taxes on or with respect to the Gas at the Delivery Point(s) and all Taxes after the Delivery Point(s). If a party is required to remit or pay Taxes that are the other party's responsibility hereunder, the party responsible for such Taxes shall promptly reimburse the other party for such Taxes. Any party entitled to an exemption from any such Taxes or charges shall furnish the other party any necessary documentation thereof.

Seller Pays Before and At Delivery Point:

Seller shall pay or cause to be paid all taxes, fees, levies, penalties, licenses or charges imposed by any government authority ("Taxes") on or with respect to the Gas prior to the Delivery Point(s) and all Taxes at the Delivery Point(s). Buyer shall pay or cause to be paid all Taxes on or with respect to the Gas after the Delivery Point(s). If a party is required to remit or pay Taxes that are the other party's responsibility hereunder, the party responsible for such Taxes shall promptly reimburse the other party for such Taxes. Any party entitled to an exemption from any such Taxes or charges shall furnish the other party any necessary documentation thereof.

SECTION 7.     BILLING, PAYMENT, AND AUDIT     

7.1.  Seller shall invoice Buyer for Gas delivered and received in the preceding Month and for any other applicable charges, providing supporting documentation acceptable in industry practice to support the amount charged. If the actual quantity delivered is not known by the billing date, billing will be prepared based on the quantity of Scheduled Gas. The invoiced quantity will then be adjusted to the actual quantity on the following Month's billing or as soon thereafter as actual delivery information is available.

7.2.  Buyer shall remit the amount due under Section 7.1 in the manner specified in the Base Contract, in immediately available funds, on or before the later of the Payment Date or 10 Days after receipt of the invoice by Buyer; provided that if the Payment Date is not a Business Day, payment is due on the next Business Day following that date. In the event any Payments are due Buyer hereunder, payment to Buyer shall be made in accordance with this Section 7.2.

7.3.  In the event payments become due pursuant to Sections 3.2 or 3.3, the performing party may submit an invoice to the nonperforming party for an accelerated payment setting forth the basis upon which the invoiced amount was calculated. Payment from the nonperforming party will be due five Business Days after receipt of invoice.

7.4.  If the invoiced party, in good faith, disputes the amount of any such invoice or any part thereof, such invoiced party will pay such amount as it concedes to be correct; provided, however, if the invoiced party disputes the amount due, it must provide supporting documentation acceptable in industry practice to support the amount paid or disputed. In the event the parties are unable to resolve such dispute, either party may pursue any remedy available at law or in equity to enforce its rights pursuant to this Section.

7.5.  If the invoiced party fails to remit the full amount payable when due, interest on the unpaid portion shall accrue from the date due until the date of payment at a rate equal to the lower of (i) the then-effective prime rate of interest published under "Money Rates" by The Wall Street Journal, plus two percent per annum; or (ii) the maximum applicable lawful interest rate.

7.6.  A party shall have the right, at its own expense, upon reasonable Notice and at reasonable times, to examine and audit and to obtain copies of the relevant portion of the books, records, and telephone recordings of the other party only to the extent reasonably necessary to verify the accuracy of any statement, charge, payment, or computation made under the Contract. This right to examine, audit, and to obtain copies shall not be available with respect to proprietary information not directly relevant to transactions under this Contract. All invoices and billings shall be conclusively presumed final and accurate and all associated claims for under- or overpayments shall be deemed waived unless such invoices or billings are objected to in writing, with adequate explanation and/or documentation, within two years after the Month of Gas delivery. All retroactive adjustments under Section 7 shall be paid in full by the party owing payment within 30 Days of Notice and substantiation of such inaccuracy.

7.7.  Unless the parties have elected on the Base Contract not to make this Section 7.7 applicable to this Contract, the parties shall net all undisputed amounts due and owing, and/or past due, arising under the Contract such that the party owing the greater amount shall make a single payment of the net amount to the other party in accordance with Section 7; provided that no payment required to be made pursuant to the terms of any Credit Support Obligation or pursuant to Section 7.3 shall be subject to netting under this Section. If the parties have executed a separate netting agreement, the terms and conditions therein shall prevail to the extent inconsistent herewith.

7


SECTION 8.     TITLE, WARRANTY, AND INDEMNITY     

8.1.  Unless otherwise specifically agreed, title to the Gas shall pass from Seller to Buyer at the Delivery Point(s). Seller shall have responsibility for and assume any liability with respect to the Gas prior to its delivery to Buyer at the specified Delivery Point(s). Buyer shall have responsibility for and any liability with respect to said Gas after its delivery to Buyer at the Delivery Point(s).

8.2.  Seller warrants that it will have the right to convey and will transfer good and merchantable title to all Gas sold hereunder and delivered by it to Buyer, free and clear of all liens, encumbrances, and claims. EXCEPT AS PROVIDED IN THIS SECTION 8.2 AND IN SECTION 14.8, ALL OTHER WARRANTIES, EXPRESS OR IMPLIED, INCLUDING ANY WARRANTY OF MERCHANTABILITY OR OF FITNESS FOR ANY PARTICULAR PURPOSE, ARE DISCLAIMED.

8.3.  Seller agrees to indemnify Buyer and save it harmless from all losses, liabilities or claims including reasonable attorneys' fees and costs of court ("Claims"), from any and all persons, arising from or out of claims of title, personal injury or property damage from said Gas or other charges thereon which attach before title passes to Buyer. Buyer agrees to indemnify Seller and save it harmless from all Claims, from any and all persons, arising from or out of claims regarding payment, personal injury or property damage from said Gas or other charges thereon which attach after title passes to Buyer.

8.4.  Notwithstanding the other provisions of this Section 8, as between Seller and Buyer, Seller will be liable for all Claims to the extent that such arise from the failure of Gas delivered by Seller to meet the quality requirements of Section 5.

SECTION 9.     NOTICES     

9.1.  All Transaction Confirmations, invoices, payments and other communications made pursuant to the Base Contract ("Notices") shall be made to the addresses specified in writing by the respective parties from time to time.

9.2.  All Notices required hereunder may be sent by facsimile or mutually acceptable electronic means, a nationally recognized overnight courier service, first class mail or hand delivered.

9.3.  Notice shall be given when received on a Business Day by the addressee. In the absence of proof of the actual receipt date, the following presumptions will apply. Notices sent by facsimile shall be deemed to have been received upon the sending party's receipt of its facsimile machine's confirmation of successful transmission. If the day on which such facsimile is received is not a Business Day or is after five p.m. on a Business Day, then such facsimile shall be deemed to have been received on the next following Business Day. Notice by overnight mail or courier shall be deemed to have been received on the next Business Day after it was sent or such earlier time as is confirmed by the receiving party. Notice via first class mail shall be considered delivered five Business Days after mailing.

SECTION 10.     FINANCIAL RESPONSIBILITY     

10.1.  If either party ("X") has reasonable grounds for insecurity regarding the performance of any obligation under this Contract (whether or not then due) by the other party ("Y") (including, without limitation, the occurrence of a material change in the creditworthiness of Y), X may demand Adequate Assurance of Performance. "Adequate Assurance of Performance" shall mean sufficient security in the form, amount and for the term reasonably acceptable to X, including, but not limited to, a standby irrevocable letter of credit, a prepayment, a security interest in an asset or a performance bond or guaranty (including the issuer of any such security).

10.2.  In the event (each an "Event of Default") either party (the "Defaulting Party") or its guarantor shall: (i) make an assignment or any general arrangement for the benefit of creditors; (ii) file a petition or otherwise commence, authorize, or acquiesce in the commencement of a proceeding or case under any bankruptcy or similar law for the protection of creditors or have such petition filed or proceeding commenced against it; (iii) otherwise become bankrupt or insolvent (however evidenced); (iv) be unable to pay its debts as they fall due; (v) have a receiver, provisional liquidator, conservator, custodian, trustee or other similar official appointed with respect to it or substantially all of its assets; (vi) fail to perform any obligation to the other party with respect to any Credit Support Obligations relating to the Contract, (vii) fail to give Adequate Assurance of Performance under Section 10.1 within 48 hours but at least one Business Day of a written request by the other party; or (viii) not have paid any amount due the other party hereunder on or before the second Business Day following written Note that such payment is due; then the other party (the "Non-Defaulting Party") shall have the right, at its sole election, to immediately withhold and/or suspend deliveries or payments upon Notice and/or to terminate and liquidate the transactions under the Contract, in the manner provided in Section 10.3, in addition to any and all other remedies available hereunder.

10.3.  If an Event of Default has occurred and is continuing, the Non-Defaulting Party shall have the right, by Notice to the Defaulting Party, to designate a Day, no earlier than the Day such Notice is given and no later than 20 Days after such Notice is given, as an early termination date (the "Early Termination Date") for the liquidation and termination pursuant to Section 10.3.1 of all transactions under the Contract, each a "Terminated Transaction". On the Early Termination Date, all transactions will terminate, other than those transactions, if any, that may not be liquidated and terminated under applicable law or that are, in the reasonable opinion of the Non-Defaulting Party, commercially impracticable to liquidate and terminate ("Excluded Transactions"), which Excluded Transactions must be liquidated and terminated as soon thereafter as is reasonably practicable, and upon termination shall be a Terminated Transaction and be valued consistent with Section 10.3.1 below. With respect to each Excluded Transaction, its actual termination date shall be the Early Termination Date for purposes of Section 10.3.1.

8


The parties have selected either "Early Termination Damages Apply" or "Early Termination Damages Do Not Apply" as indicated on the Base Contract.

Early Termination Damages Apply:

        10.3.1.  As of the Early Termination Date, the Non-Defaulting Party shall determine, in good faith and in a commercially reasonable manner, (i) the amount owed (whether or not then due) by each party with respect to all Gas delivered and received between the parties under Terminated Transactions and Excluded Transactions on and before the Early Termination Date and all other applicable charges relating to such deliveries and receipts (including without limitation any amounts owed under Section 3.2), for which payment has not yet been made by the party that owes such payment under this Contract and (ii) the Market Value, as defined below, of each Terminated Transaction. The Non-Defaulting Party shall (x) liquidate and accelerate each Terminated Transaction at its Market Value, so that each amount equal to the difference between such Market Value and the Contract Value, as defined below, of such Terminated Transaction(s) shall be due to the Buyer under the Terminated Transaction(s) if such Market Value exceeds the Contract Value and to the Seller if the opposite is the case; and (y) where appropriate, discount each amount then due under clause (x) above to present value in a commercially reasonable manner as of the Early Termination Date (to take account of the period between the date of liquidation and the date on which such amount would have otherwise been due pursuant to the relevant Terminated Transactions).

For purposes of this Section 10.3.1, "Contract Value" means the amount of Gas remaining to be delivered or purchased under a transaction multiplied by the Contract Price, and "Market Value" means the amount of Gas remaining to be delivered or purchased under a transaction multiplied by the market price for a similar transaction at the Delivery Point determined by the Non-Defaulting Party in a commercially reasonable manner. To ascertain the Market Value, the Non-Defaulting Party may consider, among other valuations, any or all of the settlement prices of NYMEX Gas futures contracts, quotations from leading dealers in energy swap contracts or physical gas trading markets, similar sales or purchases and any other bona fide third-party offers, all adjusted for the length of the term and differences in transportation costs. A party shall not be required to enter into a replacement transaction(s) in order to determine the Market Value. Any extension(s) of the term of a transaction to which parties are not bound as of the Early Termination Date (including but not limited to "evergreen provisions") shall not be considered in determining Contract Values and Market Values. For the avoidance of doubt, any option pursuant to which one party has the right to extend the term of a transaction shall be considered in determining Contract Values and Market Values. The rate of interest used in calculating net present value shall be determined by the Non-Defaulting Party in a commercially reasonable manner.

Early Termination Damages Do Not Apply:

        10.3.1.  As of the Early Termination Date, the Non-Defaulting Party shall determine, in good faith and in a commercially reasonable manner, the amount owed (whether or not then due) by each party with respect to all Gas delivered and received between the parties under Terminated Transactions and Excluded Transactions on and before the Early Termination Date and all other applicable charges relating to such deliveries and receipts (including without limitation any amounts owed under Section 3.2), for which payment has not yet been made by the party that owes such payment under this Contract.

The parties have selected either "Other Agreement Setoffs Apply" or "Other Agreement Setoffs Do Not Apply" as indicated on the Base Contract.

Other Agreement Setoffs Apply:

        10.3.2.  The Non-Defaulting Party shall net or aggregate, as appropriate, any and all amounts owing between the parties under Section 10.3.1, so that all such amounts are netted or aggregated to a single liquidated amount payable by one party to the other (the "Net Settlement Amount"). At its sole option and without prior Notice to the Defaulting Party, the Non-Defaulting Party may setoff (i) any Net Settlement Amount owed to the Non-Defaulting Party against any margin or other collateral held by it in connection with any Credit Support Obligation relating to the Contract; or (ii) any Net Settlement Amount payable to the Defaulting Party against any amount(s) payable by the Defaulting Party to the Non-Defaulting Party under any other agreement or arrangement between the parties.

Other Agreement Setoffs Do Not Apply:

        10.3.2.  The Non-Defaulting Party shall net or aggregate, as appropriate, any and all amounts owing between the parties under Section 10.3.1, so that all such amounts are netted or aggregated to a single liquidated amount payable by one party to the other (the "Net Settlement Amount"). At its sole option and without prior Notice to the Defaulting Party, the Non-Defaulting Party may setoff any Net Settlement Amount owed to the Non-Defaulting Party against any margin or other collateral held by it in connection with any Credit Support Obligation relating to the Contract.

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        10.3.3.  If any obligation that is to be included in any netting, aggregation or setoff pursuant to Section 10.3.2 is unascertained, the Non-Defaulting Party may in good faith estimate that obligation and net, aggregate or setoff, as applicable, in respect of the estimate, subject to the Non-Defaulting Party accounting to the Defaulting Party when the obligation is ascertained. Any amount not then due which is included in any netting, aggregation or setoff pursuant to Section 10.3.2 shall be discounted to net present value in a commercially reasonable manner determined by the Non-Defaulting Party.

10.4.  As soon as practicable after a liquidation, Notice shall be given by the Non-Defaulting Party to the Defaulting Party of the Net Settlement Amount, and whether the Net Settlement Amount is due to or due from the Non-Defaulting Party. The Notice shall include a written statement explaining in reasonable detail the calculation of such amount, provided that failure to give such Notice shall not affect the validity or enforceability of the liquidation or give rise to any claim by the Defaulting Party against the Non-Defaulting Party. The Net Settlement Amount shall be paid by the close of business on the second Business Day following such Notice, which date shall not be earlier than the Early Termination Date. Interest on any unpaid portion of the Net Settlement Amount shall accrue from the date due until the date of payment at a rate equal to the lower of (i) the then-effective prime rate of interest published under "Money Rates" by The Wall Street Journal, plus two percent per annum; or (ii) the maximum applicable lawful interest rate.

10.5.  The parties agree that the transactions hereunder constitute a "forward contract" within the meaning of the United States Bankruptcy Code and that Buyer and Seller are each "forward contract merchants" within the meaning of the United States Bankruptcy Code.

10.6.  The Non-Defaulting Party's remedies under this Section 10 are the sole and exclusive remedies of the Non-Defaulting Party with respect to the occurrence of any Early Termination Date. Each party reserves to itself all other rights, setoffs, counterclaims and other defenses that it is or may be entitled to arising from the Contract.

10.7.  With respect to this Section 10, if the parties have executed a separate netting agreement with close-out netting provisions, the terms and conditions therein shall prevail to the extent inconsistent herewith.

SECTION 11.     FORCE MAJEURE     

11.1.  Except with regard to a party's obligation to make payment(s) due under Section 7, Section 10.4, and Imbalance Charges under Section 4, neither party shall be liable to the other for failure to perform a Firm obligation, to the extent such failure was caused by Force Majeure. The term "Force Majeure" as employed herein means any cause not reasonably within the control of the party claiming suspension, as further defined in Section 11.2.

11.2.  Force Majeure shall include, but not be limited to, the following: (i) physical events such as acts of God, landslides, lightning, earthquakes, fires, storms or storm warnings, such as hurricanes, which result in evacuation of the affected area, floods, washouts, explosions, breakage or accident or necessity of repairs to machinery or equipment or lines of pipe; (ii) weather related events affecting an entire geographic region, such as low temperatures which cause freezing or failure of wells or lines of pipe; (iii) interruption and/or curtailment of Firm transportation and/or storage by Transporters; (iv) acts of others such as strikes, lockouts or other industrial disturbances, riots, sabotage, insurrections or wars; and (v) governmental actions such as necessity for compliance with any court order, law, statute, ordinance, regulation, or policy having the effect of law promulgated by a governmental authority having jurisdiction. Seller and Buyer shall make reasonable efforts to avoid the adverse impacts of a Force Majeure and to resolve the event or occurrence once it has occurred in order to resume performance.

11.3.  Neither party shall be entitled to the benefit of the provisions of Force Majeure to the extent performance is affected by any or all of the following circumstances: (i) the curtailment of interruptible or secondary Firm transportation unless primary, in-path, Firm transportation is also curtailed; (ii) the party claiming excuse failed to remedy the condition and to resume the performance of such covenants or obligations with reasonable dispatch; or (iii) economic hardship, to include, without limitation, Seller's ability to sell Gas at a higher or more advantageous price than the Contract Price, Buyer's ability to purchase Gas at a lower or more advantageous price than the Contract Price, or a regulatory agency disallowing, in whole or in part, the pass through of costs resulting from this Agreement; (iv) the loss of Buyer's market(s) or Buyer's inability to use or resell Gas purchased hereunder, except, in either case, as provided in Section 11.2; or (v) the loss or failure of Seller's gas supply or depletion of reserves, except, in either case, as provided In Section 11.2. The party claiming Force Majeure shall not be excused from its responsibility for Imbalance Charges.

11.4.  Notwithstanding anything to the contrary herein, the parties agree that the settlement of strikes, lockouts or other industrial disturbances shall be within the sole discretion of the party experiencing such disturbance.

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11.5.  The party whose performance is prevented by Force Majeure must provide Notice to the other party. Initial Notice may be given orally; however, written Notice with reasonably full particulars of the event or occurrence is required as soon as reasonably possible. Upon providing written Notice of Force Majeure to the other party, the affected party will be relieved of its obligation, from the onset of the Force Majeure event, to make or accept delivery of Gas, as applicable, to the extent and for the duration of Force Majeure, and neither party shall be deemed to have failed in such obligations to the other during such occurrence or event.

11.6.  Notwithstanding Sections 11.2 and 11.3, the parties may agree to alternative Force Majeure provisions in a Transaction Confirmation executed in writing by both parties.

SECTION 12.     TERM     

This Contract may be terminated on 30 Days written Notice, but shall remain in effect until the expiration of the latest Delivery Period of any transaction(s). The rights of either party pursuant to Section 7.6 and Section 10, the obligations to make payment hereunder, and the obligation of either party to indemnify the other, pursuant hereto shall survive the termination of the Base Contract or any transaction.

SECTION 13.     LIMITATIONS     

FOR BREACH OF ANY PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED, SUCH EXPRESS REMEDY OR MEASURE OF DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY. A PARTY'S LIABILITY HEREUNDER SHALL BE LIMITED AS SET FORTH IN SUCH PROVISION, AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. IF NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY PROVIDED HEREIN OR IN A TRANSACTION, A PARTY'S LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY. SUCH DIRECT ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY, AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. UNLESS EXPRESSLY HEREIN PROVIDED, NEITHER PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE. TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID HEREUNDER ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OR OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT AND THE DAMAGES CALCULATED HEREUNDER CONSTITUTE A REASONABLE APPROXIMATION OF THE HARM OR LOSS.

SECTION 14.     MISCELLANEOUS     

14.1.  This Contract shall be binding upon and inure to the benefit of the successors, assigns, personal representatives, and heirs of the respective parties hereto, and the covenants, conditions, rights and obligations of this Contract shall run for the full term of this Contract. No assignment of this Contract, in whole or in part, will be made without the prior written consent of the non-assigning party (and shall not relieve the assigning party from liability hereunder), which consent will not be unreasonably withheld or delayed; provided, either party may (i) transfer, sell, pledge, encumber, or assign this Contract or the accounts, revenues, or proceeds hereof in connection with any financing or other financial arrangements, or (ii) transfer its interest to any parent or affiliate by assignment, merger or otherwise without the prior approval of the other party. Upon any such assignment, transfer and assumption, the transferor shall remain principally liable for and shall not be relieved of or discharged from any obligations hereunder.

14.2.  If any provision in this Contract is determined to be invalid, void or unenforceable by any court having jurisdiction, such determination shall not invalidate, void, or make unenforceable any other provision, agreement or covenant of this Contract.

14.3.  No waiver of any breach of this Contract shall be held to be a waiver of any other or subsequent breach.

14.4.  This Contract sets forth all understandings between the parties respecting each transaction subject hereto, and any prior contracts, understandings and representations, whether oral or written, relating to such transactions are merged into and superseded by this Contract and any effective transaction(s). This Contract may be amended only by a writing executed by both parties.

14.5.  The interpretation and performance of this Contract shall be governed by the laws of the jurisdiction as indicated on the Base Contract, excluding, however, any conflict of laws rule which would apply the law of another jurisdiction.

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14.6.  This Contract and all provisions herein will be subject to all applicable and valid statutes, rules, orders and regulations of any governmental authority having jurisdiction over the parties, their facilities, or Gas supply, this Contract or transaction or any provisions thereof.

14.7.  There is no third party beneficiary to this Contract.

14.8.  Each party to this Contract represents and warrants that it has full and complete authority to enter into and perform this Contract. Each person who executes this Contract on behalf of either party represents and warrants that it has full and complete authority to do so and that such party will be bound thereby.

14.9.  The headings and subheadings contained in this Contract are used solely for convenience and do not constitute a part of this Contract between the parties and shall not be used to construe or interpret the provisions of this Contract.

14.10.  Unless the parties have elected on the Base Contract not to make this Section 14.10 applicable to this Contract, neither party shall disclose directly or indirectly without the prior written consent of the other party the terms of any transaction to a third party (other than the employees, lenders, royalty owners, counsel, accountants and other agents of the party, or prospective purchasers of all or substantially all of a party's assets or of any rights under this Contract, provided such persons shall have agreed to keep such terms confidential) except (i) in order to comply with any applicable law, order, regulation, or exchange rule, (ii) to the extent necessary for the enforcement of this Contract, (iii) to the extent necessary to implement any transaction, or (iv) to the extent such information is delivered to such third party for the sole purpose of calculating a published index. Each party shall notify the other party of any proceeding of which it is aware which may result in disclosure of the terms of any transaction (other than as permitted hereunder) and use reasonable efforts to prevent or limit the disclosure. The existence of this Contract is not subject to this confidentiality obligation. Subject to Section 13, the parties shall be entitled to all remedies available at law or in equity to enforce, or seek relief in connection with this confidentiality obligation. The terms of any transaction hereunder shall be kept confidential by the parties hereto for one year from the expiration of the transaction.

In the event that disclosure is required by a governmental body or applicable law, the party subject to such requirement may disclose the material terms of this Contract to the extent so required, but shall promptly notify the other party, prior to disclosure, and shall cooperate (consistent with the disclosing party's legal obligations) with the other party's efforts to obtain protective orders or similar restraints with respect to such disclosure at the expense of the other party.

14.11  The parties may agree to dispute resolution procedures in Special Provisions attached to the Base Contract or in a Transaction Confirmation executed in writing by both parties.

DISCLAIMER: The purposes of this Contract are to facilitate trade, avoid misunderstandings and make more definite the terms of contracts of purchase and sale of natural gas. Further, NAESB does not mandate the use of this Contract by any party. NAESB DISCLAIMS AND EXCLUDES, AND ANY USER OF THIS CONTRACT ACKNOWLEDGES AND AGREES TO NAESB'S DISCLAIMER OF, ANY AND ALL WARRANTIES, CONDITIONS OR REPRESENTATIONS, EXPRESS OR IMPLIED, ORAL OR WRITTEN, WITH RESPECT TO THIS CONTRACT OR ANY PART THEREOF, INCLUDNG ANY AND ALL IMPLIED WARRANTIES OR CONDITIONS OF TITLE, NON-INFRINGEMENT, MERCHANTABILITY, OR FITNESS OR SUITABILITY FOR ANY PARTICULAR PURPOSE (WHETHER OR NOT NAESB KNOWS, HAS REASON TO KNOW, HAS BEEN ADVISED, OR IS OTHERWISE IN FACT AWARE OF ANY SUCH PURPOSE), WHETHER ALLEGED TO ARISE BY LAW, BY REASON OF CUSTOM OR USAGE IN THE TRADE, OR BY COURSE OF DEALING. EACH USER OF THIS CONTRACT ALSO AGREES THAT UNDER NO CIRCUMSTANCES WILL NAESB BE LIABLE FOR ANY DIRECT, SPECIAL, INCIDENTAL, EXEMPLARY, PUNITIVE OR CONSEQUENTIAL DAMAGES ARISING OUT OF ANY USE OF THIS CONTRACT.

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    TRANSACTION CONFIRMATION
FOR IMMEDIATE DELIVERY
  EXHIBIT A

Letterhead/Logo

 

 

 

Date:                           ,           
Transaction Confirmation #:                          

This Transaction Confirmation is subject to the Base Contract between Seller and Buyer dated                          . The terms of this Transaction Confirmation are binding unless disputed in writing specified within 2 Business Days of receipt unless otherwise specified in the Base Contract.

SELLER:   BUYER:


   


   


   
Attn:  

  Attn:    
Phone:  

  Phone:    
Fax:  

  Fax:    
Base Contract No.  

  Base Contract No.    
Transporter:  

  Transporter:    
Transporter Contract Number:  

  Transporter Contract Number:    

Contract Price: $                          /MMBtu or                                                                                                   

Delivery Period: Begin:                          ,         

 

End:                          ,         
Performance Obligation and Contract Quantity: (Select One)
Firm (Fixed Quantity):
                          MMBtus/day
o EFP
  Firm (Variable Quantity):
                          MMBtus/day Minimum
                          MMBtus/day Maximum
subject to Section 4.2 at election of
o Buyer or o Seller
  Interruptible:
Up to                            MMBtus/day

Delivery Point(s):                                                  
(If a pooling point is used, list a specific geographic and pipeline location):

Special Conditions:

 

 

 

 
         
         
         
Seller:   [NOT FOR EXECUTION]

  Buyer:   [NOT FOR EXECUTION]

By:  

  By:    
Title:  

  Title:    
Date:  

  Date:    

13



SPECIAL PROVISIONS TO BASE CONTRACT FOR
SALE AND PURCHASE OF NATURAL GAS (FORM NAESB Standard 6.3.1)
BY AND BETWEEN SHELL ENERGY NORTH AMERICA (US), L.P. AND DALLAS CLEAN ENERGY, LLC
DATED MARCH 30, 2009

SECTION

1.2   Oral Transaction Procedure:

 

 

Delete the fifth sentence, and replace with the following: "Notwithstanding the foregoing sentence, the parties agree that Confirming Party shall, and the other party may, confirm a telephonic transaction by sending the other party a Transaction Confirmation by facsimile, EDI or mutually agreeable electronic means within three Business Days of a transaction covered by the Section 1.2 (Oral Transaction Procedure); provided, however, the parties agree that with respect to any transaction having a Delivery Period of less than one Month that such transactions shall be documented by a recording of the telephone transaction, which recording may be made by either or both parties, and that neither party shall submit a written Transaction Confirmation. If any transaction having a Delivery Period of less than one Month is not recorded by the Confirming Party, then the Confirming Party shall, and the other party may, confirm such transaction by sending a Transaction Confirmation by facsimile, EDI or mutually agreeable electronic means. The failure to send a Transaction Confirmation shall not invalidate the oral agreement of the parties."

1.4

 

At the end of Section 1.4, insert the following text: "For those transactions documented by telephone recordings, no such transaction shall be vitiated should a malfunction occur in equipment regularly utilized for recording transactions or retaining any recorded transactions or the operation thereof, and in such event the transaction shall be evidenced by the written and computer records of the parties concerning the transaction made contemporaneously with the telephone conversation."

2.27

 

At the end of the sentence add the phrase: "except for those transactions having a Delivery Period of less than one Month which are documented by telephone recordings pursuant to Section 1.2."

5

 

Add the following sentence at the end of the paragraph: "EXCEPT FOR THE OTHER PROVISIONS IN THIS SECTION 5, SELLER HEREBY NEGATES ALL EXPRESS, IMPLIED, OR STATUTORY REPRESENTATIONS AND WARRANTIES OF ANY KIND, INCLUDING THOSE RELATING TO MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE, OR ARISING FROM COURSE OF DEALING OR USAGE OF TRADE."

10.1

 

At the end of Section 10.1, insert the following sentence: "In the event that Shell Energy North America (US), L.P. maintains either an S&P issuer rating of BBB- or a Moody's corporate issuer rating of Baa3, or higher, then Shell Energy North America (US), L.P. shall not be required to provide any Adequate Assurance of Performance."

10.3.1

 

Add the following sentence to the end of the first paragraph of Section 10.3.1: "If the determination pursuant to clauses (x) and (y) above of the difference between the Market Value(s) and Contract Value(s) of all the Terminated Transactions does not result in an amount being owed to the Non-Defaulting Party, it shall be deemed that such difference is zero."

11.2

 

Insert the phrase "and (vi) a claim of Force Majeure of the foregoing type by a third party supplying the Gas delivered or to be delivered hereunder" before the period and after the word "jurisdiction" in the seventh line of Section 11.2.

12

 

Delete the second sentence of Section 12 and replace it with the following: "The rights of either party pursuant to: (i) Section 7.6, (ii) Section 10, (iii) Section 13, (iv) Section 14.10, (v) Waiver of Jury Trial provisions (if applicable), (vi) Arbitration provisions (if applicable), (vii) the obligation to make payment hereunder, and (viii) the obligation of either party to indemnify the other pursuant hereto, shall survive the termination of the Base Contract or any transaction."

14.10

 

Add the following new sentence to the end of the first paragraph of Section 14.10: "With respect to financial statements provided in connection with the Contract, this obligation shall survive for a period of three (3) years following the date such financial statements were provided to a party."

 

INITIAL/APPROVAL    
COUNTERPARTY  

SHELL ENERGY  




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General Terms and Conditions Base Contract for Sale and Purchase of Natural Gas
SPECIAL PROVISIONS TO BASE CONTRACT FOR SALE AND PURCHASE OF NATURAL GAS (FORM NAESB Standard 6.3.1) BY AND BETWEEN SHELL ENERGY NORTH AMERICA (US), L.P. AND DALLAS CLEAN ENERGY, LLC DATED MARCH 30, 2009

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Exhibit 10.51

FIRST AMENDMENT TO LOAN AGREEMENT

        THIS FIRST AMENDMENT TO LOAN AGREEMENT (herein called the "Amendment") made as of July 28, 2009 by and between CLEAN ENERGY, a California corporation (the "Lender") and Dallas Clean Energy, LLC., a Delaware limited liability company (formerly CE Dallas Renewables LLC) (the "Borrower").

W I T N E S S E T H:

        WHEREAS, the Borrower and Lender entered into that certain Loan Agreement dated as of August 15, 2008 (as amended, supplemented, or restated to the date hereof, the "Original Loan Agreement"), for the purpose and consideration therein expressed, whereby Lender became obligated to make loans to the Borrower as therein provided; and

        WHEREAS, the Borrower and Lender desire to amend the Original Loan Agreement as set forth herein;

        NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained herein and in the Original Loan Agreement, in consideration of the loans which may hereafter be made by Lender to the Borrower, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto do hereby agree as follows:

ARTICLE I.

DEFINITIONS AND REFERENCES

        § 1.1.     Terms Defined in the Original Loan Agreement.     Unless the context otherwise requires or unless otherwise expressly defined herein, the terms defined in the Original Loan Agreement shall have the same meanings whenever used in this Amendment.

        § 1.2.     Other Defined Terms.     Unless the context otherwise requires, the following terms when used in this Amendment shall have the meanings assigned to them in this Section 1.2.

        " Amendment " means this First Amendment to Original Loan Agreement.

        " Loan Agreement " means the Original Loan Agreement as amended hereby.

ARTICLE II.

AMENDMENTS TO ORIGINAL LOAN AGREEMENT

        § 2.1.     Recitals.     Section D of the Original Loan Agreement is hereby amended in its entirety to read as follows:

        § 2.2.     Repayment Terms.     Section 1.1(c) of the Original Loan Agreement is hereby amended in its entirety to read as follows:


ARTICLE III.

CONDITIONS OF EFFECTIVENESS

        § 3.1.     Effective Date.     This Amendment shall become effective as of the date first above written when and only when:

ARTICLE IV.

REPRESENTATIONS AND WARRANTIES

        § 4.1.     Representations and Warranties of the Borrower.     In order to induce Lender to enter into this Amendment, the Borrower represents and warrants to Lender that:

ARTICLE V.

MISCELLANEOUS

        § 5.1.     Ratification of Agreements.     The Original Loan Agreement as hereby amended is hereby ratified and confirmed in all respects. Any reference to the Loan Agreement in any Loan document

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shall be deemed to be a reference to the Original Loan Agreement as hereby amended. The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of Lender under the Original Loan Agreement or any other Loan document nor constitute a waiver of any provision of the Original Loan Agreement or any other Loan document.

        § 5.2.     Survival of Agreements.     All representations, warranties, covenants and agreements of each Borrower herein shall survive the execution and delivery of this Amendment and the performance hereof, including without limitation the making or granting of the Loans, and shall further survive until all of the Obligations are paid in full. All statements and agreements contained in any certificate or instrument delivered by any Borrower hereunder or under the Loan Agreement to Lender shall be deemed to constitute representations and warranties by, and/or agreements and covenants of, such Borrower under this Amendment and under the Loan Agreement.

        § 5.3.     Governing Law.     This Amendment shall be governed by and construed in accordance the laws of the State of California and any applicable laws of the United States of America in all respects, including construction, validity and performance.

        § 5.4.     Counterparts; Fax.     This Amendment may be separately executed in counterparts and by the different parties hereto in separate counterparts, each of which when so executed shall be deemed to constitute one and the same Amendment. This Amendment may be validly executed by facsimile or other electronic transmission.

        § 5.5.     Confirmation of Draw and Concurrent Repayment.     Lender and Borrower hereby confirm the request by Borrower and approval by Lender of a Loan under the Agreement, as hereby amended, in the principal amount of $2,800,000 to be made on or before July 31, 2009 and to be immediately repaid by Borrower to Lender. The receipt and repayment of such Loan by Borrower shall, in addition to other Loans borrowed by Borrower under the Agreement, decrease the remaining principal amount available to Borrower under the Agreement by such $2,800,000.

         THIS AMENDMENT AND THE ORIGINAL LOAN AGREEMENT REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS OF THE PARTIES.

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        IN WITNESS WHEREOF, this Amendment is executed as of the date first above written.

    DALLAS CLEAN ENERGY, LLC, as a Borrower

 

 

By:

 

/s/ EVAN G. WILLIAMS

        Name:   Evan G. Williams
             
        Title:   Manager
             

 

 

CLEAN ENERGY, as the Lender

 

 

By:

 

/s/ MITCHELL W. PRATT

        Name:   Mitchell W. Pratt
             
        Title:   SVP & Corporate Secretary
             



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FIRST AMENDMENT TO LOAN AGREEMENT

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Exhibit 31.1

Certifications

I, Andrew J. Littlefair, certify that:

        1.     I have reviewed this Form 10-Q of Clean Energy Fuels Corp.;

        2.     Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

        3.     Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

        4.     The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

        5.     The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

Date: August 10, 2009

/s/ ANDREW J. LITTLEFAIR

Andrew J. Littlefair,
President and Chief Executive Officer
(Principal Executive Officer)
   



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Certifications

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Exhibit 31.2

Certifications

I, Richard R. Wheeler, certify that:

        1.     I have reviewed this Form 10-Q of Clean Energy Fuels Corp.;

        2.     Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

        3.     Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

        4.     The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

        5.     The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

Date: August 10, 2009

/s/ RICHARD R. WHEELER

Richard R. Wheeler,
Chief Financial Officer
(Principal Financial Officer)
   



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Certifications

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Exhibit 32.1

CERTIFICATION REQUIRED BY
SECTION 1350 OF TITLE 18 OF THE UNITED STATES CODE

        Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, each of the undersigned hereby certifies in his capacity as the specified officer of Clean Energy Fuels Corp. (the Company) that, to the best of his knowledge, the quarterly report of the Company on Form 10-Q for the fiscal quarter ended June 30, 2009 fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, and that the information contained in such report fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods presented in the financial statements included in such report.

Dated: August 10, 2009

/s/ ANDREW J. LITTLEFAIR

Name: Andrew J. Littlefair
Title:
President and Chief Executive Officer
(Principal Executive Officer)
   

Dated: August 10, 2009

/s/ RICHARD R. WHEELER

Name: Richard R. Wheeler
Title:
Chief Financial Officer
(Principal Financial Officer)
   

        This certification accompanies this Report on Form 10-Q pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act, except to the extent that the Company specifically incorporates it by reference.




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CERTIFICATION REQUIRED BY SECTION 1350 OF TITLE 18 OF THE UNITED STATES CODE