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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, 2011

Commission File Number: 001-33480

CLEAN ENERGY FUELS CORP.

(Exact name of registrant as specified in its charter)

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

(Address of principal executive offices, including zip code)

(562) 493-2804

(Registrant’s telephone number, including area code)

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

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

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

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

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

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CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

INDEX

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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, 2010 and June 30, 2011 (Unaudited)

(In thousands, except share data)

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, 2010 and 2011

(Unaudited)

(In thousands, except share and per share data)

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, 2010 and 2011

(Unaudited)

(In thousands)

See accompanying notes to condensed consolidated financial statements.

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Clean Energy Fuels Corp. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(In thousands, except share data)

Note 1—General

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

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

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

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

Note 2—Acquisitions

Natural Gas Fueling Compressors

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

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

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

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

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

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

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

Liquefied Natural Gas Station Construction

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

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

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

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

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

Note 3—Cash and Cash Equivalents

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

Note 4—Derivative Transactions

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

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

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Note 5—Other Receivables

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

Note 6—Inventories

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

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

Note 7—Land, Property and Equipment

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

Note 8—Investments in Other Entities

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

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

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Note 9—Accrued Liabilities

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

Note 10—Warranty Liability

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

Note 11—Long-term Debt

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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:

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

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Note 13—Comprehensive Loss

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

Note 14—Stock-Based Compensation

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

Stock Options

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

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

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

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

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

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

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

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

Note 16—Income Taxes

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

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

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

Note 17—Fair Value Measurements

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

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

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

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

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

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

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

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

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

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

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

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

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

Note 20—Subsequent Events

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

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

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

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

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

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

Cautionary Statement Regarding Forward Looking Statements

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

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

Overview

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

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

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

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

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

The number of fueling stations we served grew from 147 at December 31, 2004 to 248 at June 30, 2011 (a 68.7% increase). Included in this number are all of the CNG and LNG fueling stations we own, maintain or with which we have a fueling supply contract. The amount of CNG and LNG gasoline gallon equivalents we delivered from 2005 to 2010 increased by 116%. The increase in gasoline gallon equivalents delivered was the primary contributor to increased revenues during these periods. Our cost of sales also increased during these periods, which was attributable primarily to increased costs related to delivering more CNG and LNG to our customers.

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

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

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

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

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

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

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

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

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

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

Operations

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

CNG Sales

We sell CNG through fueling stations located on our customers’ properties and through our network of public access fueling stations. At these CNG fueling stations, we procure natural gas from local utilities or brokers under standard, floating-rate arrangements and then compress and dispense it into our customers’ vehicles. Our CNG sales are made primarily through contracts with our fleet customers. Under these contracts, pricing is determined primarily on an index-plus basis, which is calculated by adding a margin to the local index or utility price for natural gas. CNG sales revenues based on an index-plus methodology increase or decrease as a result of an increase or decrease in the price of natural gas. We also sell a small amount of CNG under fixed-price contracts. We will continue to offer fixed price contracts as appropriate and consistent with our natural gas hedging policy that was revised in May 2008. Our fleet customers typically are billed monthly based on the volume of CNG sold at a station. The remainder of our CNG sales are on a per fill-up basis at prices we set at the pump based on prevailing market conditions. These customers typically pay using a credit card at the station.

LNG Sales

We sell substantially all of our LNG to fleet customers, who typically own and operate their fueling stations. We also sell LNG to customers at our five public LNG stations and for non-vehicle use. During 2011, we procured 42% of our LNG from third-party producers, and we produced the remainder of the LNG at our liquefaction plants in Texas and California. For LNG that we purchase from third parties, we may enter into “take or pay” contracts that require us to purchase minimum volumes of LNG at index-based rates. We deliver LNG via our fleet of 58 tanker trailers to fueling stations, where it is stored and dispensed in liquid form into vehicles. We sell LNG principally through supply contracts that are priced on either a fixed-price or index-plus basis. LNG sales revenues based on an index-plus methodology increase or decrease as a result of an increase or decrease in the price of natural gas. We will continue to offer fixed price contracts as appropriate and consistent with our natural gas hedging policy that was revised in May 2008. Our LNG contracts provide that we charge our customers periodically based on the volume of LNG supplied or sold.

America’s Natural Gas Highway

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

Government Incentives

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

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

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Operation and Maintenance

We generate a significant portion of our revenue from operation and maintenance agreements for CNG fueling stations where we do not supply the fuel. We refer to this portion of our business as “O&M.” At these fueling stations, the customer contracts directly with a local broker or utility to purchase natural gas. For O&M services, we do not sell the fuel itself, but generally charge a per-gallon fee based on the volume of fuel dispensed at the station. We include the volume of fuel dispensed at the stations at which we provide O&M services in our calculation of aggregate gasoline gallon equivalents sold.  Through Northstar, we also generate O&M revenues for LNG fueling stations.  In these instances, we may or may not also supply LNG to the station.

Station Construction

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

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

Vehicle Acquisition and Finance

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

Landfill Gas

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

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

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

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

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

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

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

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

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

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

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

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

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

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Vehicle Conversions

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

Natural Gas Fueling Compressors

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

Volatility of Earnings and Cash Flows

Our earnings and cash flows historically have fluctuated significantly from period to period based on our futures activities, as all of our futures contracts entered into prior to June 30, 2008 have not qualified for hedge accounting under the relevant derivative accounting guidance. We have therefore recorded any changes in the fair market value of these contracts that did not qualify for hedge accounting directly in our statements of operations in the line item derivative (gains) losses along with any realized gains or losses generated during the period. We experienced a derivative loss of $0.3 million in the year ended December 31, 2008. Subsequent to June 30, 2008, our futures contracts did qualify for hedge accounting, so we had no derivative gains or losses in the years ended December 31, 2009 and 2010 and during the six month period ended June 30, 2011 related to our futures contracts. In accordance with our natural gas hedging policy, we plan to structure all subsequent futures contracts as cash flow hedges under the applicable derivative accounting guidance, but we cannot be certain that they will qualify. See “Risk Management Activities” below. If the futures contracts do not qualify for hedge accounting, we could incur significant increases or decreases in our earnings based on fluctuations in the market value of the contracts from period to period.

Additionally, we are required to maintain a margin account to cover losses related to our natural gas futures contracts. Futures contracts are valued daily, and if our contracts are in loss positions at the end of a trading day, our broker will transfer the amount of the losses from our margin account to a clearinghouse. If at any time the funds in our margin account drop below a specified maintenance level, our broker will issue a margin call that requires us to restore the balance. Consequently, these payments could significantly impact our cash balances. At June 30, 2011, we had $3.6 million on deposit in margin accounts, which are included in prepaid expenses and other current assets and notes receivable and other long-term assets in our balance sheet.

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

Volatility of Earnings Related to Series I Warrants

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

Volatility of Earnings Related to Contingent Consideration

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

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

Debt Compliance

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

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

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

Risk Management Activities

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

Critical Accounting Policies

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

Recently Issued Accounting Pronouncements

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

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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 as a percentage of total revenues: