Clean Energy Fuels Corp.
Clean Energy Fuels Corp. (Form: 10-Q, Received: 05/07/2012 16:14:33)

Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

 

FORM 10-Q

 

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

THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended March 31, 2012

 

Commission File Number: 001-33480

 

CLEAN ENERGY FUELS CORP.

(Exact name of registrant as specified in its charter)

 

Delaware

 

33-0968580

(State or other jurisdiction of incorporation)

 

(IRS Employer Identification No.)

 

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

(Address of principal executive offices, including zip code)

 

(562) 493-2804

(Registrant’s telephone number, including area code)

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No  o

 

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

 

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

 

Large accelerated filer  o

 

Accelerated filer  x

 

 

 

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

 

Smaller reporting company  o

 

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

 

As of May 1, 2012, there were 86,588,898 shares of the registrant’s common stock, par value $0.0001 per share, issued and outstanding.

 

 

 



Table of Contents

 

CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

 

INDEX

 

Table of Contents

 

PART I.—FINANCIAL INFORMATION

 

Item 1.—Financial Statements (Unaudited)

3

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

21

Item 3.—Quantitative and Qualitative Disclosures About Market Risk

32

Item 4.—Controls and Procedures

33

PART II.—OTHER INFORMATION

 

Item 1.—Legal Proceedings

34

Item 1A.—Risk Factors

34

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

45

Item 3.—Defaults upon Senior Securities

45

Item 4.—Mine Safety Disclosures

45

Item 5.—Other Information

45

Item 6.—Exhibits

46

 

2



Table of Contents

 

PART I.—FINANCIAL INFORMATION

 

Item 1.—Financial Statements (Unaudited)

 

Clean Energy Fuels Corp. and Subsidiaries

 

Condensed Consolidated Balance Sheets

 

December 31, 2011 and March 31, 2012 (Unaudited)

 

(In thousands, except share data)

 

 

 

December 31,
2011

 

March 31,
2012

 

Assets

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

238,125

 

$

190,666

 

Restricted cash

 

4,792

 

8,450

 

Short-term investments

 

33,329

 

37,893

 

Accounts receivable, net of allowance for doubtful accounts of $712 and $666 as of December 31, 2011 and March 31, 2012, respectively

 

56,455

 

61,161

 

Other receivables

 

19,601

 

17,036

 

Inventory, net

 

35,287

 

38,536

 

Prepaid expenses and other current assets

 

14,027

 

13,966

 

Total current assets

 

401,616

 

367,708

 

Land, property and equipment, net

 

277,334

 

309,939

 

Restricted cash

 

54,804

 

41,512

 

Notes receivable and other long-term assets

 

16,650

 

17,689

 

Investments in other entities

 

16,459

 

16,954

 

Goodwill

 

73,741

 

73,741

 

Intangible assets, net

 

102,103

 

99,732

 

Total assets

 

$

942,707

 

$

927,275

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Current portion of long-term debt and capital lease obligations

 

$

22,925

 

$

30,837

 

Accounts payable

 

36,668

 

28,097

 

Accrued liabilities

 

28,255

 

30,080

 

Deferred revenue

 

21,267

 

25,948

 

Total current liabilities

 

109,115

 

114,962

 

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

 

266,497

 

254,949

 

Other long-term liabilities

 

22,687

 

33,831

 

Total liabilities

 

398,299

 

403,742

 

Commitments and contingencies (Note 16)

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

Preferred stock, $0.0001 par value. Authorized 1,000,000 shares; issued and outstanding no shares

 

 

 

Common stock, $0.0001 par value. Authorized 149,000,000 shares; issued and outstanding 85,433,258 shares and 86,329,061 shares at December 31, 2011 and March 31, 2012, respectively

 

9

 

9

 

Additional paid-in capital

 

741,650

 

752,276

 

Accumulated deficit

 

(199,559

)

(231,464

)

Accumulated other comprehensive loss

 

(1,216

)

(950

)

Total Clean Energy Fuels Corp. stockholders’ equity

 

540,884

 

519,871

 

Noncontrolling interest in subsidiary

 

3,524

 

3,662

 

Total stockholders’ equity

 

544,408

 

523,533

 

Total liabilities and stockholders’ equity

 

$

942,707

 

$

927,275

 

 

See accompanying notes to condensed consolidated financial statements.

 

3



Table of Contents

 

Clean Energy Fuels Corp. and Subsidiaries

 

Condensed Consolidated Statements of Operations

 

For the Three Months Ended March 31, 2011 and 2012

 

(Unaudited)

 

(In thousands, except share and per share data)

 

 

 

Three Months Ended
March 31,

 

 

 

2011

 

2012

 

Revenue:

 

 

 

 

 

Product revenues

 

$

58,532

 

$

65,776

 

Service revenues

 

6,809

 

7,858

 

Total revenues

 

65,341

 

73,634

 

Operating expenses:

 

 

 

 

 

Cost of sales:

 

 

 

 

 

Product cost of sales

 

43,850

 

51,902

 

Service cost of sales

 

3,154

 

3,984

 

Derivative (gains) losses:

 

 

 

 

 

Series I warrant valuation

 

3,300

 

13,506

 

Selling, general and administrative

 

18,030

 

24,850

 

Depreciation and amortization

 

7,210

 

8,144

 

Total operating expenses

 

75,544

 

102,386

 

Operating loss

 

(10,203

)

(28,752

)

Interest expense, net

 

(820

)

(3,702

)

Other income, net

 

601

 

841

 

Income from equity method investments

 

211

 

91

 

Loss before income taxes

 

(10,211

)

(31,522

)

Income tax (expense) benefit

 

735

 

(246

)

Net loss

 

(9,476

)

(31,768

)

Income of noncontrolling interest

 

(277

)

(137

)

Net loss attributable to Clean Energy Fuels Corp.

 

$

(9,753

)

$

(31,905

)

Loss per share attributable to Clean Energy Fuels Corp.:

 

 

 

 

 

Basic and diluted

 

$

(0.14

)

$

(0.37

)

Weighted-average common shares outstanding:

 

 

 

 

 

Basic and diluted

 

70,096,000

 

85,677,090

 

 

See accompanying notes to condensed consolidated financial statements.

 

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Table of Contents

 

Clean Energy Fuels Corp. and Subsidiaries

 

Condensed Consolidated Statements of Comprehensive Income

 

For the Three Months Ended March 31, 2011 and 2012

 

(Unaudited)

 

(In thousands)

 

 

 

Clean Energy Fuels Corp.

 

Noncontrolling Interest

 

Total

 

 

 

Three Months Ended
March 31,

 

Three Months Ended
March 31,

 

Three Months Ended
March 31,

 

 

 

2011

 

2012

 

2011

 

2012

 

2011

 

2012

 

Net income (loss)

 

$

(9,753

)

$

(31,905

)

$

277

 

$

137

 

$

(9,476

)

$

(31,768

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other comprehensive income, net of tax:

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign currency translation adjustments

 

(702

)

(333

)

 

 

(702

)

(333

)

Unrealized gains (losses) on available-for-sale securities

 

 

(116

)

 

 

 

(116

)

Unrecognized gains (losses) on derivatives

 

708

 

715

 

 

 

708

 

715

 

Total other comprehensive income, net of tax

 

6

 

266

 

 

 

6

 

266

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income (loss)

 

$

(9,747

)

$

(31,639

)

$

277

 

$

137

 

$

(9,470

)

$

(31,502

)

 

See accompanying notes to condensed consolidated financial statements.

 

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Table of Contents

 

Clean Energy Fuels Corp.

 

Condensed Consolidated Statements of Cash Flows

 

For the Three Months Ended March 31, 2011 and 2012

 

(Unaudited)

 

(In thousands)

 

 

 

Three Months Ended
March 31,

 

 

 

2011

 

2012

 

Cash flows from operating activities:

 

 

 

 

 

Net loss

 

$

(9,476

)

$

(31,768

)

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

 

 

 

 

 

Depreciation and amortization

 

7,210

 

8,144

 

Asset impairments

 

45

 

 

Provision for doubtful accounts, notes and inventory

 

79

 

209

 

Derivative loss

 

3,300

 

13,506

 

Stock-based compensation expense

 

3,377

 

4,680

 

Amortization of debt issuance cost

 

 

113

 

Accretion of notes payable

 

720

 

555

 

(Gain) on contingent consideration for acquisitions

 

(696

)

(2,648

)

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

 

 

 

 

 

Accounts and other receivables

 

24,388

 

(2,218

)

Inventory

 

(6,511

)

(3,369

)

Margin deposits on futures contracts

 

1,760

 

 

Prepaid expenses and other assets

 

(1,379

)

(1,151

)

Accounts payable

 

(8,021

)

(8,571

)

Accrued expenses and other

 

(4,899

)

7,439

 

Net cash provided by (used in) operating activities

 

9,897

 

(15,079

)

Cash flows from investing activities:

 

 

 

 

 

Purchases of short-term investments

 

 

(4,564

)

Purchases of property and equipment

 

(10,816

)

(38,929

)

Restricted cash related to DCEMB bond offering

 

(27,061

)

9,634

 

Investments in other entities

 

(2,700

)

 

Net cash used in investing activities

 

(40,577

)

(33,859

)

Cash flows from financing activities:

 

 

 

 

 

Proceeds from issuance of common stock and exercise of stock options

 

394

 

5,947

 

Proceeds from capital lease obligations and debt instruments

 

41,548

 

76

 

Proceeds from revolving line of credit

 

10,240

 

15,069

 

Proceeds from minority interest DCE equity contribution

 

417

 

 

Payments for debt issuance costs

 

(1,767

)

 

Repayment of borrowing under revolving line of credit

 

(7,340

)

(15,002

)

Repayment of capital lease obligations and debt instruments

 

(15,199

)

(5,547

)

Net cash provided by financing activities

 

28,293

 

543

 

Effect of exchange rates on cash and cash equivalents

 

(858

)

936

 

Net decrease in cash

 

(3,245

)

(47,459

)

Cash, beginning of period

 

55,194

 

238,125

 

Cash, end of period

 

$

51,949

 

$

190,666

 

Supplemental disclosure of cash flow information:

 

 

 

 

 

Income taxes paid

 

$

597

 

$

559

 

Interest paid, net of approximately $118 and $1,517 capitalized, respectively

 

131

 

2,359

 

 

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. The Company began selling certain equipment and services internationally in 2010 as a result of its acquisition of I.M.W. Industries, Ltd. (“IMW”).

 

The Company has a broad customer base in a variety of markets, including trucking, airports, taxis, refuse, and public transit. The Company, builds, operates, maintains or supplies approximately 300 natural gas fueling locations in twenty-six states within the United States, and in British Columbia and Ontario within Canada. The Company also generates revenue through operation and maintenance (“O&M”) agreements with certain customers, through building and selling or leasing natural gas fueling stations to its customers, through manufacturing and servicing natural gas fueling compressors and related equipment, providing natural gas vehicle conversions, processing and selling renewable natural gas (“RNG”), and through financing its customers’ vehicle purchases.

 

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

 

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

 

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

 

Note 2—Acquisitions

 

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, and has other manufacturing facilities near Shanghai, China and in Ferndale, Washington, and has sales and service offices in Bangladesh, Colombia, Peru and the United States.

 

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 $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

 

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on January 31, 2011, (ii) a promissory note with a principal amount of $12,500 that was 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. On January 31, 2012, the Company paid $5,000 in cash and extended the additional payment due on January 31, 2012 to July 31, 2012.

 

IMW’s former shareholder may also receive additional contingent consideration based on future gross profits earned by IMW over the four year period following the acquisition. 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 IMW shareholder earned $235 for the first contingent consideration payment.

 

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:

 

Current assets

 

$

27,149

 

Property, plant and equipment

 

2,559

 

Identifiable intangible assets

 

81,400

 

Goodwill

 

45,049

 

Total assets acquired

 

156,157

 

Liabilities assumed

 

(25,986

)

Total purchase price

 

$

130,171

 

 

Management allocated approximately $81,400 of the purchase price to the identifiable intangible assets related to technology, customer relationships, non-compete agreements, and trademarks that were acquired with the acquisition. The fair value of the identifiable intangible assets will be amortized on a straight-line basis over their estimated useful lives ranging from three to twenty years. In addition, management allocated $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. As of March 31, 2012, the fair value of the contingent consideration was approximately $3,330.

 

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 liquefied natural gas (“LNG”) and liquefied to compressed (“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. In December 2011, the Company made its first annual payment of $700 and paid an installment of $990 in retention bonuses to certain key employees.

 

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed as of December 15, 2010:

 

Current assets

 

$

4,434

 

Property, plant and equipment

 

941

 

Identifiable intangible assets

 

3,350

 

Goodwill

 

5,228

 

Total assets acquired

 

13,953

 

Liabilities assumed

 

(3,648

)

Total purchase price

 

$

10,305

 

 

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Management allocated $2,250 of the purchase price to the identifiable intangible assets related to non-compete agreements, customer relationships, and backlog. The fair value of these identifiable intangibles will be amortized on a straight-line basis over their estimated 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.

 

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—Restricted Cash

 

The Company classifies restricted cash as a current asset if the cash is expected to be used in operations within a year or to acquire a current asset. Otherwise, the restricted cash is classified as long-term. Restricted cash consisted of the following as of December 31, 2011 and March 31, 2012:

 

 

 

December 31,
2011

 

March 31,
2012

 

Short-term restricted cash

 

 

 

 

 

Standby letters of credit

 

$

1,237

 

$

2,824

 

DCEMB bonds – current operating costs

 

3,555

 

5,626

 

Total short-term restricted cash

 

4,792

 

8,450

 

Chesapeake loan

 

40,322

 

31,982

 

DCEMB bonds – long-term plant expansion

 

14,482

 

9,530

 

Total restricted cash

 

$

59,596

 

$

49,962

 

 

Note 5—Investments

 

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

 

Available-for-sale securities as of March 31, 2012 are summarized as follows:

 

 

 

Amortized
Cost

 

Gross
Unrealized
Loss

 

Market
Value

 

Municipal bonds & notes

 

$

25,281

 

$

(234

)

$

25,047

 

Zero coupon bonds

 

810

 

 

810

 

Corporate bonds

 

2,023

 

(8

)

2,015

 

Total available-for-sale securities

 

28,114

 

(242

)

27,872

 

Certificate of deposits

 

10,021

 

 

10,021

 

Total short-term investments

 

$

38,135

 

$

(242

)

$

37,893

 

 

The Company had no available-for-sale securities as of March 31, 2011.

 

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Note 6—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 applicable accounting guidance. The Company recorded unrealized (gains) losses of $(708) and $(715), in other comprehensive income (loss) for the three month periods ended March 31, 2011 and 2012, respectively, related to its futures contracts. Of the $1,543 liability for the Company’s futures contracts at March 31, 2012, $1,496 is included in accrued liabilities for the short-term amount, and $47 is included in other long-term liabilities for the long-term amount in the Company’s condensed consolidated balance sheet as of March 31, 2012. Of the $3,363 liability for the Company’s futures contracts at March 31, 2011, $2,851 is included in accrued liabilities for the short-term amount, and $512 is included in other long-term liabilities for the long-term amount in the Company’s condensed consolidated balance sheet as of March 31, 2011. The Company’s ineffectiveness related to its futures contracts during the three month periods ended March 31, 2011 and 2012 was insignificant. For the three months ended March 31, 2011 and 2012, the Company recognized a loss of approximately $751 and $1,107, respectively, in cost of sales in the accompanying condensed consolidated statement of operations related to its futures contracts that were settled during the respective periods.

 

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 March 31, 2012:

 

 

 

Gallons

 

Weighted
Average Price
Per Gasoline
Gallon
Equivalent

 

April to December, 2012

 

2,720,000

 

$

0.81

 

January to May, 2013

 

300,000

 

$

0.81

 

 

Note 7—Other Receivables

 

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

 

 

 

December 31,
2011

 

March 31,
2012

 

Loans to customers to finance vehicle purchases

 

$

1,789

 

$

1,961

 

Capital lease receivables

 

310

 

297

 

Accrued customer billings

 

5,860

 

5,657

 

Fuel tax and carbon credits

 

5,912

 

4,059

 

Other

 

5,730

 

5,062

 

 

 

$

19,601

 

$

17,036

 

 

Note 8—Inventories

 

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

 

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

 

 

 

December 31,
2011

 

March 31,
2012

 

Raw materials and spare parts

 

$

30,177

 

$

33,432

 

Work in process

 

2,310

 

2,370

 

Finished goods

 

2,800

 

2,734

 

Total

 

$

35,287

 

$

38,536

 

 

Note 9—Land, Property and Equipment

 

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

 

 

 

December 31,
2011

 

March 31,
2012

 

Land

 

$

1,198

 

$

1,198

 

LNG liquefaction plants

 

93,109

 

93,297

 

RNG plants

 

21,005

 

22,257

 

Station equipment

 

118,613

 

130,374

 

LNG trailers

 

13,532

 

13,532

 

Other equipment

 

26,508

 

29,117

 

Construction in progress

 

86,127

 

108,970

 

 

 

360,092

 

398,745

 

Less: accumulated depreciation

 

(82,758

)

(88,806

)

 

 

$

277,334

 

$

309,939

 

 

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Note 10—Investments in Other Entities

 

Through March 31, 2012, the Company has invested approximately $13,515 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 80.1% of ServoTech for $2,800 over the 15 month period following the Closing Date (the “Purchase Option”). On April 30, 2012, the Company exercised the Purchase Option, paid $1,400 in cash on that date and agreed to pay an additional $1,400 in cash on October 31, 2012. Through March 31, 2012, the Company accounted for its interest using the equity method of accounting as the Company had the ability to exercise significant influence over ServoTech’s operations. Beginning April 1, 2012, the Company will consolidate the financial results of ServoTech into its financial results.

 

Note 11—Accrued Liabilities

 

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

 

 

 

December 31,
2011

 

March 31,
2012

 

Salaries and wages

 

$

5,088

 

$

4,914

 

Accrued gas and equipment purchases

 

4,773

 

4,539

 

Derivative liability

 

2,259

 

1,496

 

Contingent consideration obligations

 

378

 

367

 

Accrued property and other taxes

 

3,043

 

2,249

 

Accrued professional fees

 

875

 

725

 

Accrued employee benefits

 

1,431

 

2,748

 

Accrued warranty liability

 

3,130

 

3,137

 

Other

 

7,278

 

9,905

 

 

 

$

28,255

 

$

30,080

 

 

Note 12—Warranty Liability

 

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

 

 

 

March 31,
2011

 

March 31,
2012

 

Warranty liability at beginning of year

 

$

2,338

 

$

3,130

 

Assumed liability through acquisitions

 

 

 

Costs accrued for new warranty contracts and changes in estimates for pre-existing warranties

 

405

 

939

 

Service obligations honored

 

(260

)

(932

)

Warranty liability at end of period

 

$

2,483

 

$

3,137

 

 

Note 13—Long-term Debt

 

In conjunction with the Company’s acquisition of its 70% interest in Dallas Clean Energy, LLC (“DCE”), on August 15, 2008, the Company entered into a credit agreement (“Credit Agreement”) with 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”).

 

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

 

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

 

Revenue Bonds

 

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

 

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

 

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

 

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

 

Pursuant to a Consent and Agreement, by and between Shell Energy, The Bank of New York Mellon Trust Company, N.A., as Depository Bank (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.

 

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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 March 31, 2012, $9,530 was recorded as long term restricted cash and $5,626 was recorded as short term restricted cash in the accompanying consolidated balance sheet.

 

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

 

The Indenture and the Loan Agreement have certain non-financial debt covenants with which DCEMB must comply. As of March 31, 2012, DCEMB was in compliance with all its debt covenants under the Indenture and the Loan Agreement.

 

Purchase Notes

 

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

 

In connection with the closing of the Company’s acquisition of Northstar, 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.

 

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

 

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

 

HSBC Lines of Credit

 

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

 

(i)                                      An operating line of credit with a limit of $10,000 in Canadian dollars (“CAD”) bearing interest at prime plus 1.25%, to assist in financing the day-to-day working capital needs of IMW.

 

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

 

(iii)                                A forward exchange contract line with a limit of CAD$13,750. The forward exchange contract line allows IMW to enter into foreign exchange forward contracts up to the notional limit of CAD$13,750 (no forward exchange contracts were outstanding at March 31, 2012).

 

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

 

(v)                                  An operating line of credit with a limit of 5,000 Renminbi (“RMB”) (CAD$791) bearing interest at the 6 month People’s Bank of China rate plus 2.5% and a sub-limit bank guarantee line of 5,000 RMB. The aggregate of the balances in the lines cannot exceed 5,000 RMB.

 

(vi)                               A 16,750 Bengali Taka (CAD$197) operating line of credit bearing interest at 14%.

 

(vii)                            A 170,000 Columbian Peso (CAD$94) operating line of credit bearing interest at the Colombia benchmark rate plus 7 to 12%.

 

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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 3.75 to 1.0 from January 1, 2012 through March 31, 2012, and greater than 3.5 to 1.0 from April 1, 2012 through June 30, 2012, and greater than 3.0 to 1.0 on or after July 1, 2012, 2) its tangible net worth at anytime be below CAD$7,000 and 3) its ratio of current assets to current liabilities to be less than 1.15 to 1.0 until March 31, 2012 and less than 1.25 to 1.0 on or after April 1, 2012. IMW was in compliance with the financial covenants as of March 31, 2012.

 

In addition, the Company and IMW agreed that should the making of any scheduled payment by IMW to the seller of IMW under the IMW Notes result in IMW being in breach of the Assumption Agreement, the IMW Lines of Credit or the Security, the Company shall furnish IMW with the funds needed to 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.

 

Chesapeake Notes

 

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

 

The first CHK Note was issued on July 11, 2011, and the Company expects to issue the second and third CHK Notes on June 29, 2012 and June 28, 2013, respectively. The CHK Notes bear interest at the rate of 7.5% per annum (payable quarterly, in arrears, on March 31, June 30, September 30 and December 31 of each year) and are convertible at Chesapeake’s option into shares of the Company’s common stock at a conversion price of $15.80 per share (the “CHK Conversion Price”). Subject to certain restrictions, the Company can force conversion of each CHK Note into shares of the Company’s common stock if, following the second anniversary of the issuance of a CHK Note, the Company’s shares of common stock trade at a 40% premium to the CHK Conversion Price for at least twenty trading days in any consecutive thirty trading day period. The entire principal balance of each CHK Note is due and payable seven years following its issuance, and the Company may repay each CHK Note in shares of the Company’s common stock or cash. The CHK Agreement restricts the use of the CHK Financing proceeds to financing the development, construction and operation of liquefied natural gas stations and payment of certain related expenses. At March 31, 2012, approximately $32,000 of these funds were included in long term restricted cash as the Company anticipates primarily using the funds to build LNG fueling stations. The CHK Agreement also provides for customary events of default which, if any of them occurs, would permit or require the principal of, and accrued interest on, the CHK Notes to become, or to be declared, due and payable.

 

In connection with the CHK Financing, the Company also entered into a Registration Rights Agreement, dated July 11, 2011, with Chesapeake (the “CHK Registration Rights Agreement”) pursuant to which the Company agreed, subject to the terms and conditions of the CHK Registration Rights Agreement, to (i) file with the Securities and Exchange Commission one or more registration statements relating to the resale of the Company’s common stock issuable upon conversion of the CHK Notes, and (ii) at the request of Chesapeake, to participate in one or more underwritten offerings of the Company’s common stock issuable upon conversion of the CHK Notes. If the Company does not meet certain of its obligations under the CHK Registration Rights Agreement with respect to the registration of the Company’s common stock, it will be required to pay monthly liquidated damages of 0.75% of the principal amount of the CHK Note represented by the Company’s common stock included (or to be included, as the case may be) in the applicable registration statement until the related obligation is met. As of March 31, 2012, the Company met its obligations under the CHK Registration Rights Agreement.

 

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Table of Contents

 

SLG Notes

 

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

 

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

 

In connection with the SLG Agreements, the Company also entered into a Registration Rights Agreement, dated August 24, 2011, with each of the Purchasers (the “SLG Registration Rights Agreements”) pursuant to which the Company agreed, subject to the terms and conditions of the SLG Registration Rights Agreements, to (i) file with the Securities and Exchange Commission one or more registration statements relating to the resale of the Company’s common stock issuable upon conversion of the SLG Notes, and (ii) at the request of the Purchasers, participate in one or more underwritten offerings of the Company’s common stock issuable upon conversion of the SLG Notes. If the Company does not meet certain of its obligations under the SLG Registration Rights Agreements with respect to the registration of the Company’s common stock, it will be required to pay monthly liquidated damages of 0.75% of the principal amount of the SLG Note represented by the Company’s common stock included (or to be included, as the case may be) in the applicable registration statement until the related obligation is met, not to exceed 4% of the aggregate principal amount of the SLG Notes per annum. As of March 31, 2012, the Company met its obligations under the SLG Registration Rights Agreement.

 

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

 

 

 

December 31,
2011

 

March 31,
2012

 

IMW future payment notes

 

$

34,400

 

$

30,153

 

Northstar future payments

 

2,388

 

2,428

 

DCE notes

 

585

 

585

 

DCEMB Revenue Bonds (non recourse to the Company)

 

39,400

 

39,400

 

Chesapeake Notes

 

50,000

 

50,000

 

SLG Notes

 

150,000

 

150,000

 

Weaver Notes

 

872

 

895

 

IMW assumed debt

 

6,657

 

7,646

 

Capital lease obligations

 

5,120

 

4,679

 

Total debt and capital lease obligations

 

289,422

 

285,786

 

Less amounts due within one year and short-term borrowings

 

(22,925

)

(30,837

)

Total long-term debt and capital lease obligations

 

$

266,497

 

$

254,949

 

 

Note 14—Earnings Per Share

 

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

 

 

 

Three Months Ended
March 31,

 

 

 

2011

 

2012

 

Basic and diluted:

 

 

 

 

 

Weighted-average number of common shares outstanding

 

70,096,000

 

85,677,090

 

 

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Certain securities were excluded from the diluted earnings per share calculations for the three months ended March 31, 2011 and 2012, respectively, as the inclusion of the securities would be anti-dilutive to the calculation. The amounts outstanding as of March 31, 2011 and 2012 for these instruments are as follows:

 

 

 

March 31,

 

 

 

2011

 

2012

 

Options

 

10,705,519

 

10,903,234

 

Warrants

 

17,130,682

 

2,130,682

 

Convertible notes

 

 

13,164,557

 

Restricted Stock Units

 

 

1,420,000

 

 

Note 15—Stock-Based Compensation

 

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

 

 

 

Three Months Ended
March 31,

 

 

 

2011

 

2012

 

Stock options:

 

 

 

 

 

Stock-based compensation expense

 

$

3,377

 

$

4,680

 

Income tax benefit

 

 

 

Stock-based compensation expense, net of tax

 

$

3,377

 

$

4,680

 

 

Stock Options

 

The following table summarizes the Company’s stock option activity during the three months ended March 31, 2012:

 

 

 

Number of
Shares

 

Weighted
Average
Exercise
Price

 

Weighted
Average
Remaining
Contractual
Term (in years)

 

Aggregate
Intrinsic
Value

 

Outstanding, December 31, 2011

 

10,683,303

 

$

10.29

 

 

 

 

 

Options granted

 

1,182,000

 

15.13

 

 

 

 

 

Options exercised

 

(895,803

)

6.64

 

 

 

 

 

Options forfeited

 

(66,266

)

13.73

 

 

 

 

 

Outstanding, March 31, 2012

 

10,903,234

 

$

11.08

 

6.53

 

$

111,266

 

Exercisable, March 31, 2012

 

7,782,772

 

$

9.73

 

5.53

 

$

89,854

 

 

As of March 31, 2012, there was $23,607 of total unrecognized compensation cost related to non-vested shares. That cost is expected to be recognized over a weighted average period of 1.4 years. The total fair value of shares vested during the three months ended March 31, 2012 was $3,080.

 

The Company plans to issue new shares to its employees upon the employee’s exercise of their options. The intrinsic value of all options exercised during the three months ended March 31, 2011 and 2012 was $541 and $12,955, respectively.

 

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

 

 

 

Three Months Ended
March 31, 2012

 

Dividend yield

 

0.00%

 

Expected volatility

 

66.7% to 66.9%

 

Risk-free interest rate

 

1.1% to 1.2%

 

Expected life in years

 

6.0

 

 

The weighted-average grant date fair values of options granted during the three months ended March 31, 2011 and 2012 were $9.11, and $9.09, respectively. The volatility amounts used during the period were estimated based on a certain peer group of the Company’s historical volatility for a period commensurate with the expected life of the options granted, the Company’s historical

 

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volatility, and the Company’s implied volatility of its traded options. The expected lives used during the periods were based on historical exercise periods and the Company’s anticipated exercise periods for its outstanding options. The risk free rates used during the year were based on the U.S. Treasury yield curve for the expected life of the options at the time of grant. The Company recorded $3,377 and $3,342 of stock option expense during the three months ended March 31, 2011 and 2012, respectively. The Company has not recorded any tax benefit related to its stock option expense.

 

Restricted Stock Units

 

The Company issued restricted stock units (“RSUs”) to certain key employees during the three months ended March 31, 2012.  A holder of RSUs will receive one share of the Company’s common stock for each RSU he holds if (x) between January 25, 2014 and January 24, 2016 the closing price of the Company’s common stock equals or exceeds, for twenty consecutive trading days, 135% of the closing price of the Company’s common stock on the RSU grant date (the closing price on the RSU grant date, January 25, 2012, was $15.11) (the “Stock Price Condition”) and (y) the holder is employed by the Company at the time the Stock Price Condition is satisfied. If the Stock Price Condition is not satisfied prior to January 24, 2016, the RSUs will be automatically forfeited. The RSUs are subject to the terms and conditions of the Company’s Amended and Restated 2006 Equity Incentive Plan and a Notice of Grant of Restricted Stock Unit and Restricted Stock Unit Agreement.

 

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

 

The following table summarizes the Company’s RSU activity during the three months ended March 31, 2012:

 

 

 

Number of
Shares

 

Weighted Average 
Fair Value at 
Grant Date

 

Weighted
Average
Remaining
Contractual
Term (in years)

 

Outstanding, December 31, 2011

 

 

$

 

 

 

Granted

 

1,420,000

 

11.31

 

 

 

Vested

 

 

 

 

 

Forfeited

 

 

 

 

 

Outstanding and non-vested, March 31, 2012

 

1,420,000

 

11.31

 

3.8

 

 

As of March 31, 2012, there was $14,722 of total unrecognized compensation cost related to non-vested units. That cost is expected to be recognized over a weighted average period of 1.8 years.

 

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

 

 

 

Three Months Ended
March 31, 2012

 

Stock price on date of grant

 

$

15.11

 

Dividend yield

 

0.00

%

Expected volatility

 

56.51

%

Risk-free interest rate

 

0.57

%

Expected life in years

 

2.1

 

 

The volatility amounts used during the period were estimated based on the Company’s historical volatility for a period commensurate with the term of the RSUs granted and the Company’s implied volatility of its traded options. The expected life of the RSUs was derived using the Monte Carlo Method. The risk free rates used during the year were based on the United States Treasury yield curve for the expected term of the RSUs at the date of grant. The Company recorded $1,338 of expense and has not recorded any tax benefit related to the expense of the RSUs during the three months ended March 31, 2012.

 

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

 

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

 

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

 

On July 15, 2010, the Internal Revenue Service (“IRS”) sent the Company a letter disallowing approximately $5,073 related to certain claims it made from October 1, 2006 to June 30, 2008 under the Volumetric Excise Tax Credit (“VETC”) program. The Company believes its claims were properly made and has appealed the IRS’s request for payment.

 

Note 17—Income Taxes

 

The Company is required to recognize the impact of a tax position in its financial statements if the position meets the more likely than not threshold of being sustained by the taxing authority upon examination, based on the technical merits of the position. The Company accrues interest based on the difference between a tax position recognized in the financial statements and the amount claimed on its returns at statutory interest rates. The net interest incurred was immaterial for the three months ended March 31, 2011 and 2012. Further, the Company accrues penalties if the tax position does not meet the minimum statutory threshold to avoid penalties. No penalties have been accrued by the Company. The Company’s unrecognized tax benefits as of March 31, 2012 are unchanged from December 31, 2011.

 

The Company is subject to taxation in the United States and various states and foreign jurisdictions. The Company’s tax years for 2007 through 2010 are subject to examination by various tax authorities. The Company is no longer subject to United States examination for years before 2008, and state examinations for years before 2007.  On July 15, 2010, the IRS sent the Company a letter disallowing approximately $5,073 related to certain claims the Company made from October 1, 2006 to June 30, 2008 under the VETC program and is seeking repayment of such amount. The Company believes its claims were properly made and has appealed the IRS’s request for payment.

 

Note 18—Fair Value Measurements

 

The Company follows authoritative guidance for fair value measurements with respect to assets and liabilities that are measured at fair value on a recurring basis and nonrecurring basis. Under the standard, fair value is defined as the exit price, or the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The standard also establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs market participants would use in valuing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions about the factors market participants would use in valuing the asset or liability developed based upon the best information available in the circumstances. The hierarchy 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 three months ended March 31, 2012, the Company’s financial instruments consisted of available-for-sale securities, natural gas futures contracts, debt instruments, a contingent consideration obligation, and its Series I warrants. For securities available-for-sale, the fair value is determined by the most recent trading prices available for each security or for comparable securities, and thus represent Level 2 fair value measurements. The Company uses quoted forward price curves, discounted to reflect the time value of money, to value its natural gas futures contracts which are considered to be a Level 2 fair value measurement. The Company uses an income approach, projecting the financial results for the associated entity, discounted to reflect the time value of money, to value its contingent consideration obligation which is considered to be a Level 3 fair value measurement. The fair market value of the Company’s debt instruments approximated their carrying values at March 31, 2011 and 2012. The Company uses the Black-Scholes model to value the Series I warrants. The Company believes the best method to approximate the market participant’s view of the volatility of its Series I warrants is to use the implied volatilities of its short-term (i.e. 3 to 9 month) traded options and extrapolate the data over the remaining term of the Series I warrants, which was approximately 4 years and 1 month as of March 31, 2012. This method has been utilized consistently in the periods presented. Given  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.

 

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

 

Description

 

Balance at
December 31,
2011

 

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

 

Significant Other
Observable
Inputs
(Level 2)

 

Significant
Unobservable
Inputs
(Level 3)

 

Assets:

 

 

 

 

 

 

 

 

 

Available-for-sale securities (1):

 

 

 

 

 

 

 

 

 

Certificate of deposits

 

$

10,000

 

$

 

$

10,000

 

$

 

Municipal bonds and notes

 

 

19,589

 

 

 

 

19,589

 

 

 

Zero coupon bonds

 

712

 

 

712

 

 

Corporate bonds

 

3,028

 

 

3,028

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

Natural gas futures contracts (2)

 

 

2,335

 

 

 

 

2,335

 

 

 

Contingent consideration obligation (3)

 

5,978

 

 

 

5,978

 

Series I warrants (4)

 

11,493

 

 

 

11,493

 

 

Description

 

Balance at
March 31,
2012

 

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

 

Significant Other
Observable
Inputs
(Level 2)

 

Significant
Unobservable
Inputs
(Level 3)

 

Assets:

 

 

 

 

 

 

 

 

 

Available-for-sale securities (1):

 

 

 

 

 

 

 

 

 

 

 

 

 

Certificate of deposits

 

$

10,021

 

$

 

$

10,021

 

$

 

Municipal bonds and notes

 

 

25,047

 

 

 

 

25,047

 

 

 

Zero coupon bonds and notes

 

 

810

 

 

 

 

810

 

 

 

Corporate bonds

 

 

2,015

 

 

 

 

2,015

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

Natural gas futures contracts (2)

 

1,543

 

 

 

1,543

 

 

Contingent consideration obligation (3)

 

3,330

 

 

 

3,330

 

Series I warrants (4)

 

24,999

 

 

 

24,999

 

 


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

(2) See note 6–Derivative Transactions for further information.

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

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

 

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

 

Liabilities: Series I Warrants

 

March 31,
2011

 

March 31,
2012

 

Beginning Balance

 

$

14,148

 

$

11,493

 

Total loss included in earnings (1)

 

3,300

 

13,506

 

Issuance of warrants

 

 

 

Exercise of warrants

 

 

 

Transfers In/Out

 

 

 

Ending Balance

 

$

17,448

 

$

24,999

 

 

Liabilities: Contingent Consideration

 

March 31,
2011

 

March 31,
2012

 

Beginning Balance

 

$

11,200

 

$

5,978

 

Business combinations

 

 

 

Total (gain) loss included in SG&A expense

 

(717

)

(2,648

)

Payments

 

 

 

Transfers In/Out

 

 

 

Ending Balance

 

$

10,483

 

$

3,330

 

 


(1) Reported on the face of the condensed consolidated statements of operations.

 

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Table of Contents

 

Valuation processes for Level 3 Fair Value Measurements

 

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

 

GRAPHIC

 

Sensitivity of Level 3 measurements to changes in significant unobservable inputs

 

Contingent Consideration

 

Pursuant to the terms presented in the Asset Purchase Agreement, the IMW shareholder will earn additional consideration if IMW achieves certain minimum gross profit targets in fiscal years 2011 through 2014.  Therefore, the Company estimated the fair value of the contingent consideration using a discounted cash flow model that considers the payout structure based on gross profit targets, the probabilities of reaching the thresholds in each year, and the risk-adjusted discount rate.  Significant changes in any of those inputs in isolation would result in a significant change in the fair value measurement.  Generally, a positive change in the assumption used for the probability of achieving a higher gross profit target threshold would result in a directionally similar change in the estimated fair value of the contingent consideration.  Conversely, an increase in the assumed discount rate would have a directionally opposite impact on the estimated fair value measurement of the contingent consideration. 

 

Series I Warrant liability

 

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

 

Non-financial assets

 

No impairments of long-lived assets measured at fair value on a non-recurring basis have been incurred during the three months ended March 31, 2011 and March 31, 2012.  The Company’s use of these nonfinancial assets does not differ from their highest and best use, as determined from the perspective of a market participant.

 

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

 

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

 

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

 

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Table of Contents

 

Note 20—Volumetric Excise Tax Credit (VETC)

 

The Company records its VETC credits as revenue in its condensed consolidated statements of operations as the credits are fully refundable and do not need to offset income tax liabilities to be received. VETC revenues for the three month periods ended March 31, 2011 and 2012 were $4,217 and $0, respectively. The VETC legislation expired on December 31, 2011.

 

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

 

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (this “MD&A”) should be read together with the unaudited condensed consolidated financial statements and the related notes included elsewhere in this report. For additional context with which to understand our financial condition and results of operations, refer to the MD&A for the fiscal year ended December 31, 2011 contained in our 2011 Annual Report on Form 10-K filed with the SEC on March 12, 2012, 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 2011 Annual Report on Form 10-K (the“2011 10-K”). In preparing this MD&A, we presume that readers have access to and have read the MD&A in our 2011 Annual Report on Form 10-K pursuant to Instruction 2 to paragraph (b) of Item 303 of Regulation S-K. We undertake no duty to update any of these forward-looking statements after the date of filing of this report to conform such forward-looking statements to actual results or revised expectations, except as otherwise required by law.

 

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

 

Overview

 

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

 

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

 

Key operating data.   In evaluating our operating performance, our management focuses primarily on: (1) the amount of CNG and LNG gasoline gallon equivalents delivered (which we define as (i) the volume of gasoline gallon equivalents we sell to our customers, plus (ii) the volume of gasoline gallon equivalents dispensed to our customers at stations where we provide operating and maintenance (“O&M”) services, but do not sell the CNG or LNG, plus (iii) our proportionate share of the gasoline gallon equivalents sold as CNG by our joint venture in Peru, plus (iv) our proportionate share of the gasoline gallon equivalents of RNG produced and sold as pipeline quality natural gas by DCE), (2) our gross margin (which we define as revenue minus cost of sales), and (3) net income (loss) attributable to us. The following table, which you should read in conjunction with our condensed consolidated financial statements and notes contained elsewhere in this quarterly report on Form 10-Q and our consolidated financial statements and notes contained in our annual report on Form 10-K for the year ended December 31, 2011, presents our key operating data for the years ended December 31, 2009, 2010, and 2011 and for the three months ended March 31, 2011 and 2012:

 

Gasoline gallon equivalents
delivered (in millions)

 

Year Ended
December 31,
2009

 

Year Ended
December 31,
2010

 

Year Ended
December 31,
2011

 

Three Months Ended
March 31,
2011

 

Three Months Ended
March 31,
2012

 

CNG

 

67.9

 

81.4

 

101.8

 

22.7

 

29.0

 

RNG

 

6.4

 

7.4

 

6.7

 

1.5

 

2.1

 

LNG

 

26.7

 

33.9

 

47.1

 

11.3

 

12.6

 

Total

 

101.0

 

122.7

 

155.6

 

35.5

 

43.7

 

 

Operating data

 

 

 

 

 

 

 

 

 

 

 

Gross margin

 

$

48,582

 

$

69,945

 

$

76,033

 

$

18,337

 

$

17,748

 

Net loss

 

(33,249

)

(2,516

)

(47,633

)

(9,753

)

(31,905

)

 

Key trends in 2009, 2010, 2011 and the first three months of 2012.   According to the Energy Information Administration, demand for natural gas fuels in the United States increased by approximately 26% during the period January 1, 2009 through December 31, 2011. We believe this growth in demand was attributable primarily to the rising prices of gasoline and diesel relative to CNG and LNG during these periods and increasingly stringent environmental regulations affecting vehicle fleets.

 

The number of fueling stations we served grew from 196 at December 31, 2009 to 298 at March 31, 2012 (a 52.0% 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 2009 to 2011 increased by 54%. The increase in gasoline gallon equivalents delivered was the primary contributor to increased revenues during 2009, 2010 and 2011. In addition, in 2011, we also benefitted from increased revenues from compressor sales and fueling station installations as a result of our acquisitions of IMW and Northstar, which occurred during the fourth quarter of 2010.

 

Our cost of sales also increased during these periods, which was attributable primarily to increased costs related to delivering more CNG and LNG to our customers in 2009 and 2010. In 2011, the cost of sales related to compressors sold through IMW and fueling station installations performed by Northstar also contributed to the increase.

 

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

 

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

 

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During 2011 and the first three months of 2012, prices for oil, gasoline, and diesel fuel generally increased, while the price for natural gas generally decreased. Oil hit a high of $107.07 in February 2012 and settled at $103.02 per barrel on March 31, 2012. In California, average retail prices for gasoline have increased from $3.68 per gallon in January 2012 to $4.41 per gallon at March 31, 2012, and average retail prices for diesel fuel have increased from $4.05 per diesel gallon in January 2012 to $4.48 per diesel gallon at March 31, 2012. Higher gasoline and diesel prices typically improve our margins on fuel sales to the extent we price fuel at a discount to gasoline or diesel. During this time period, the price for natural gas declined. The NYMEX price for natural gas fluctuated from $3.08 per MMbtu in January 2012 to $2.41 per MMbtu at March 31, 2012. The average retail sales price of our CNG fuel sold in the Los Angeles metropolitan area ranged from $2.60 for the month of January 2011 to $2.90 for the month of March 2012. The average retail sales price of our LNG fuel sold in the Los Angeles metropolitan area ranged from $2.50 for the month of January 2011 to $2.90 at the end of March 31, 2012.

 

Anticipated future trends.   We anticipate that, over the long term, the prices for gasoline and diesel will continue to be significantly higher than the price of natural gas as a vehicle fuel, and more stringent emissions requirements will continue to make natural gas vehicles an attractive alternative to traditional gasoline and diesel powered vehicles. Our belief that natural gas will continue, over the long term, to be a cheaper vehicle fuel than gasoline or diesel is based in large part on the growth in United States natural gas production.

 

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

 

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

 

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

 

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

 

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

 

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

 

Many governmental entities, which represented approximately 44% of our revenues from 2007 through 2011, are experiencing significant budget deficits as a result of the economic recession and have been, and may continue to be, unable to invest in new natural gas vehicles for their transit or refuse fleets. They may also be compelled to reduce public transportation and services, or the prices they pay for these services, which would negatively affect our business.

 

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

 

Our business plan calls for approximately $188.9 million in capital expenditures from April 1, 2012 through the end of 2012, primarily related to construction of new fueling stations, including ANGH stations, expanding our California LNG plant, expanding and building landfill gas processing plants, and the purchase of LNG trailers. We may also elect to invest additional amounts in companies or assets in the natural gas fueling infrastructure, services and production industries, including RNG production. We will need to raise additional capital as necessary to fund any capital expenditures or investments that we cannot fund through available cash or cash generated by operations. The timing and necessity of any future capital raise will depend on our rate of new station construction and potential merger or acquisition activity. For more information, see “Liquidity and Capital Resources” and “Capital Expenditures” below. We may not be able to raise capital on terms that are favorable to existing stockholders or at all. Any inability to raise capital may impair our ability to invest in new stations, develop natural gas fueling infrastructure and invest in strategic transactions or acquisitions, and may reduce our ability to grow our business and generate increased revenues.

 

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

 

Operations

 

We generate revenues principally by selling CNG and LNG and providing O&M services to our vehicle fleet customers. For the three months ended March 31, 2012, CNG and RNG (together) represented 71% and LNG represented 29% of our natural gas sales (on a gasoline gallon equivalent basis). To a lesser extent, we generate revenues by designing and constructing fueling stations and selling or leasing those stations to our customers. We also generate material revenues through sales of RNG produced by our joint venture subsidiary DCE, sales of natural gas vehicles by our wholly owned subsidiary BAF, sales of advanced natural gas fueling compressors and related equipment and maintenance services through IMW, and sales of LNG and LCNG fueling station design, construction and O&M services through Northstar. Substantially all of our operating and maintenance revenues are generated from CNG stations, as owners of LNG stations typically tend to operate and maintain their own stations. Substantially all of our station sale and leasing revenues have been generated from CNG stations.

 

CNG Sales

 

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

 

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LNG Sales

 

We sell LNG to fleet customers, who typically own and operate their fueling stations. Increasingly, we also sell LNG to fleet and other customers at our public-access LNG stations and for non-vehicle use, such as power generation. During 2011, we procured 43% of our LNG from third-party producers, and we produced the remainder of the LNG at our liquefaction plants in Texas and California. For LNG that we purchase from third parties, we may enter into “take or pay” contracts that require us to purchase minimum volumes of LNG at index-based rates. We deliver LNG via our fleet of 58 tanker trailers to fueling stations, where it is stored and dispensed in liquid form into vehicles. We sell LNG principally through supply contracts that are priced on either a fixed-price or index-plus basis. LNG sales revenues based on an index-plus methodology increase or decrease as a result of an increase or decrease in the price of natural gas. We will continue to offer fixed price contracts as appropriate and consistent with our natural gas hedging policy. Our LNG contracts provide that we charge our customers periodically based on the volume of LNG supplied. We also sell LNG on a per fill-up basis at prices we set at the pump based on prevailing market conditions. These customers typically pay using a credit card at the station.

 

America’s Natural Gas Highway

 

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

 

Government Incentives

 

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

 

On July 15, 2010, the IRS sent us a letter (i) disallowing approximately $5.1 million related to certain claims we made from October 1, 2006 to June 30, 2008 under the Volumetric Excise Tax Credit program, and (ii) seeking repayment of such amount. We believe our claims were properly made and are contesting the IRS’s determination.

 

Operation and Maintenance

 

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

 

Station Construction

 

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

 

On December 15, 2010, we completed the purchase of Northstar, an entity that provides design, engineering, construction and maintenance services for LNG and LCNG fueling stations. For the three months ended March 31, 2011 and 2012, Northstar contributed approximately $3.6 million and $2.1 million, respectively, to our revenue.

 

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Vehicle Acquisition and Finance

 

In 2006, we commenced offering vehicle finance services for some of our customers’ purchases of natural gas vehicles or the conversion of their existing gasoline or diesel powered vehicles to operate on natural gas. We loan to certain qualifying customers a portion of, and on occasion up to 100% of, the purchase price of their natural gas vehicles. We may also lease vehicles in the future. Where appropriate, we apply for and receive state and federal incentives associated with natural gas vehicle purchases and pass these benefits through to our customers. We may also secure vehicles to place with customers or pay deposits with respect to such vehicles prior to receiving a firm order from our customers, which we may be required to purchase if our customer fails to purchase the vehicle as anticipated. Through March 31, 2012, we have not generated significant revenue from vehicle financing activities.

 

Landfill Gas

 

In August 2008, we acquired 70% of the outstanding membership interests of DCE for a purchase price of $19.6 million including transaction costs. DCE owns a facility that collects, processes and sells RNG from the McCommas Bluff landfill located in Dallas, Texas.  For the three months ended March 31, 2011 and 2012, DCE generated approximately $2.8 million and $3.6 million, respectively, in revenue from sales of RNG, all of which is included in our condensed consolidated statements of operations.

 

On April 3, 2009, DCE entered into a fifteen year gas sale agreement with Shell Energy North America (US), L.P. (“Shell”) for the sale by DCE to Shell of biomethane produced by DCE’s landfill gas processing facility (the “Shell Gas Sale Agreement”). In April 2012, the Shell Gas Sale Agreement was amended to extend the term to 2034 and increase the amount of RNG sold under the agreement.

 

DCE retains the right to reserve from the Shell Gas Sale Agreement up to 500 MMBtus per day of RNG for sale as a vehicle fuel. To the extent that DCE produces volumes of RNG in excess of the volumes sold under the agreement with Shell, DCE will either attempt to sell such volumes at then-prevailing market prices or seek to enter into another gas sale agreement in the future. DCE may not produce or be able to sell up to the maximum volumes called for under the agreement. DCE’s ability to produce RNG is dependent on a number of factors beyond DCE’s control including, but not limited to, the availability and composition of the landfill gas that is collected, the operation of the landfill by the City of Dallas and the reliability of the processing plant’s critical equipment. The processing equipment is currently being expanded and upgraded, which may result in significant down time to complete the work, which consequently may reduce DCE’s sales of RNG during the expansion and upgrade period. The expansion and upgrade work is anticipated to continue through 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 May 7, 2012.

 

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

 

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

 

Vehicle Conversions

 

On October 1, 2009, we completed our acquisition of BAF. Founded in 1992, BAF provides natural gas vehicle conversions, alternative fuel systems, application engineering, service and warranty support and research and development. BAF’s vehicle conversions include taxis, vans, pick-up trucks and shuttle buses. BAF utilizes advanced natural gas system integration technology and has certified NGVs under both EPA and CARB standards achieving Super Ultra Low Emission Vehicle emissions. We generate revenues through the sale of natural gas vehicles that have been converted to run on natural gas by BAF. The majority of BAF’s revenue during 2010 and 2011 was derived from sales of converted natural gas service vans to AT&T. During both the first quarter of 2011 and 2012, BAF contributed approximately $3.6 million and $8.3 million, respectively, to our revenue.

 

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Natural Gas Fueling Compressors

 

On September 7, 2010, we completed our purchase of IMW. IMW manufactures and services advanced, non-lubricated natural gas fueling compressors and related equipment for the global natural gas fueling market. IMW is headquartered near Vancouver, British Columbia, has other manufacturing facilities near Shanghai, China and in Ferndale, Washington, and has sales and service offices in Bangladesh, Colombia, Peru and the United States. For the three months ended March 31, 2011 and 2012, IMW contributed approximately $16.7 million and $13.5 million, respectively, to our revenue.

 

Volatility of Earnings and Cash Flows

 

During 2009, 2010, and 2011, our futures contracts qualified for hedge accounting, so we had no derivative gains or losses recognized in our consolidated statements of operations for the years ended December 31, 2009, 2010, and 2011. In accordance with our natural gas hedging policy, we plan to structure all futures contracts as cash flow hedges under the applicable derivative accounting guidance, but we cannot be certain that they will qualify. See “Risk Management Activities” below. If the futures contracts do not qualify for hedge accounting, we could incur significant increases or decreases in our earnings based on fluctuations in the market value of the contracts from period to period.

 

Additionally, we are required to maintain a margin account to cover losses related to our natural gas futures contracts. Futures contracts are valued daily, and if our contracts are in loss positions at the end of a trading day, our broker will transfer the amount of the losses from our margin account to a clearinghouse. If at any time the funds in our margin account drop below a specified maintenance level, our broker will issue a margin call that requires us to restore the balance. Consequently, these payments could significantly impact our cash balances. At March 31, 2012, we had $3.6 million of margin deposits, 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 corresponding margin deposits required thereon could significantly impact our financial position in the future.

 

Volatility of Earnings Related to Series I Warrants

 

Beginning January 1, 2009, under Financial Accounting Standards Board (“FASB”) authoritative guidance, we are required to record the change in the fair market value of our Series I warrants in our consolidated financial statements. We have recognized a loss (gain) of $3.3 million and $13.5 million related to recording the estimated fair market value changes of our Series I warrants in the three months ended March 31, 2011 and 2012, respectively. See note 18 to our condensed consolidated financial statements contained elsewhere herein. Our earnings or loss per share may be materially affected by future gains or losses we are required to recognize as a result of valuing our Series I warrants. On November 10, 2010, 1,183,712 of the Series I warrants were exercised and thus, were not outstanding during 2011. As of March 31, 2012, 2,130,682 of the Series I warrants remained outstanding.

 

Volatility of Earnings Related to Contingent Consideration

 

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

 

If the anticipated results of IMW increase or decrease during future periods, we may be required to recognize material losses or gains based on the valuation of the increased or decreased consideration due to the former IMW shareholder. During the first quarter of 2012, we recognized a gain of $2.6 million related to the estimated change in the value of the IMW contingent consideration. Our earnings or loss per share may be materially affected by future gains or losses we are required to recognize as a result of changes in the estimated fair value of the contingent consideration amount.

 

Debt Compliance

 

In connection with our acquisition of IMW, we entered into a credit agreement with HSBC that requires IMW to comply with certain financial covenants. Among these financial covenants are that IMW shall not permit: 1) its ratio of debt to tangible net worth to be greater than 3.75 to 1.0 from January 1, 2012 through March 31, 2012, and greater than 3.5 to 1.0 from April 1, 2012 through June 30, 2012, and greater than 3.0 to 1.0 on or after July 1, 2012, 2) its tangible net worth at anytime be below CAD$7,000 and 3) its ratio of current assets to current liabilities to be less than 1.15 to 1.0 until March 31, 2012 and less than 1.25 to 1.0 on or after April 1, 2012. 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 does not grant a waiver, all of the obligations under the credit agreement would be due and payable. IMW was in compliance with these covenants as of March 31, 2012.

 

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The Indenture and the Loan Agreement DCEMB entered into as part of issuing its Revenue Bonds, as defined and disclosed in note 13 to our condensed consolidated financial statements, each have certain non-financial debt covenants with which DCEMB must comply. As of March 31, 2012, DCEMB was in compliance with its debt covenants.

 

The Loan Agreement we entered into as part of issuing the CHK Notes, as defined and discussed in note 13 to our condensed consolidated financial statements, has certain non-financial debt covenants with which we must comply. As of March 31, 2012, we were in compliance with these debt covenants under the Indenture and the Loan Agreement.

 

The Convertible Note Purchase Agreements we entered into as part of issuing the SLG Notes, as defined and discussed in note 13 to our condensed consolidated financial statements, have certain non-financial debt covenants with which we must comply. As of March 31, 2012, we were in compliance with these covenants.

 

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

 

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

 

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

 

Risk Management Activities

 

Our risk management activities, including the revised natural gas hedging policy, are discussed elsewhere in this quarterly report on Form 10-Q and in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operation) of our 2011 10-K. For the quarter ended March 31, 2012, there were no material changes to our risk management activities.

 

Critical Accounting Policies

 

For the three months ended March 31, 2012, there were no material changes to the “Critical Accounting Policies” discussed in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) of our 2011 Annual Report on Form 10-K.

 

Recently Issued Accounting Pronouncements

 

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

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Results of Operations

 

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

 

 

 

Three Months
Ended
March 31,

 

 

 

2011

 

2012

 

Statement of Operations Data:

 

 

 

 

 

Revenue:

 

 

 

 

 

Product revenues

 

89.6

%

89.3

%

Service revenues

 

10.4

 

10.7

 

Total operating revenues

 

100.0

 

100.0

 

Operating expenses:

 

 

 

 

 

Cost of sales:

 

 

 

 

 

Product cost of sales

 

67.1

 

70.5

 

Service cost of sales

 

4.8

 

5.4

 

Derivative loss on Series I warrant valuation

 

5.1

 

18.3

 

Selling, general and administrative

 

27.6

 

33.7

 

Depreciation and amortization

 

11.0

 

11.1

 

Total operating expenses

 

115.6

 

139.0

 

Operating loss

 

(15.6

)

(39.0

)

Interest expense, net

 

(1.2

)

(5.0

)

Other income, net

 

0.9

 

1.1

 

Income from equity method investment

 

0.3

 

0.1

 

Loss before income taxes

 

(15.6

)

(42.8

)

Income tax benefit (expense)

 

1.1

 

(0.3

)

Net loss

 

(14.5

)

(43.1

)

Income of noncontrolling interest

 

(0.4

)

(0.2

)

Net loss attributable to Clean Energy Fuels Corp.

 

(14.9

)

(43.3

)

 

Three Months Ended March 31, 2011 Compared to Three Months Ended March 31, 2012

 

Revenue.   Revenue increased by $8.3 million to $73.6 million in the three months ended March 31, 2012, from $65.3 million in the three months ended March 31, 2011. A portion of this increase was the result of an increase in the number of gallons delivered between periods from 35.5 million gasoline gallon equivalents to 43.7 million gasoline gallon equivalents. The increase in volume was primarily from an increase in CNG sales of 6.3 million gallons. Our net increase in CNG volume was primarily from eight new refuse customers, two new stations from an existing transit customer, two new trucking customers, and one new airport customer, which together accounted for 3.5 million gallons of the CNG volume increase. We also experienced an increase of 2.8 gallons in CNG volume between periods from our existing refuse, airport, and transit customers, combined with the volume growth from our share of our joint venture in Peru. We also experienced a net increase of 1.3 million gallons in LNG volume between periods, which was primarily due to 1.3 million gallons from Northstar O&M services. We experienced an increase in our RNG sales (our 70% share of the RNG sales at DCE) of 0.6 million gallons due to increased RNG production at DCE’s facility. We experienced a $7.0 million increase, excluding Northstar, in station construction revenues between periods, primarily due to the completion of two new CNG stations for new trucking customers, one new CNG station for an existing trucking customer, two new CNG stations for new refuse customers, one CNG station upgrade for an existing refuse customer, one new CNG station for a transit customer, one CNG station upgrade for an existing transit customer, and one new CNG station for a new airport customer.  Revenue also increased by $4.7 million between periods due to increased sales of natural gas vehicle equipment by BAF. These increases were offset by a slight decrease in our effective price per gallon that we charged to our customers between periods. Our effective price per gallon was $0.83 in the three months ended March 31, 2012, which represents a $0.03 per gallon decrease from $0.86 in the three months ended March 31, 2011. The decrease was primarily due to lower natural gas prices in the first quarter of 2012, upon which we base a portion of our pricing to our customers. IMW and Northstar contributed $3.2 million and $1.5 million, respectively, to our decreased revenue between periods. Revenue attributable to VETC also decreased between periods as we did not record any revenue related to fuel tax credits in the first quarter of 2012 as the fuel tax credits expired on December 31, 2011, and we recorded $4.2 million of revenue related to fuel tax credits during the first quarter of 2011.

 

Cost of sales.   Cost of sales increased by $8.9 million to $55.9 million in the three months ended March 31, 2012, from $47.0 million in the three months ended March 31, 2011. Our cost of sales primarily increased between periods as a result of delivering more volume to our customers. We experienced a $7.7 million increase, excluding Northstar, in station construction costs between periods. We also experienced a $3.1 million increase in costs related to BAF’s vehicle equipment sales between periods as BAF’s sales of natural gas vehicle equipment increased. These increases were offset by the decrease in our effective cost per gallon of $0.07 per gallon, to $0.55 per gallon, in the three months ended March 31, 2012. This decrease was primarily the result of lower natural gas prices in the first quarter of 2012. IMW and Northstar contributed $3.5 million and $0.8 million, respectively, to our decreased cost of sales between periods.

 

Derivative loss on Series I warrant valuation.   Derivative loss increased by $10.2 million to $13.5 million in the three months ended March 31, 2012, from $3.3 million in the three months ended March 31, 2011. The amounts represent the non-cash impact with respect to valuing our outstanding Series I warrants based on our mark-to-market accounting for the warrants during the periods. (See note 18 to our condensed consolidated financial statements contained elsewhere herein.)

 

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Selling, general and administrative.   Selling, general and administrative expenses increased by $6.8 million to $24.8 million in the three months ended March 31, 2012, from $18.0 million in the three months ended March 31, 2011. The most significant increase was our salaries and benefits amount increasing by $3.5 million between periods as we increased our employee headcount from 747 at March 31, 2011 to 1,038 at March 31, 2012. We also experienced a $3.0 million increase in consulting, marketing, employee recruiting, business insurance, rent and occupancy, software/hardware maintenance, research and development, and office supplies expense related to our continued business growth. Stock option expense also increased between periods by $1.3 million. Our travel and entertainment expenses increased $1.0 million between periods, primarily due to the increased travel of our sales team. These increases were offset by a $2.6 million gain related to a decrease in the estimated fair value of the IMW contingent consideration liabilities between periods.

 

Depreciation and amortization.   Depreciation and amortization increased by $0.9 million to $8.1 million in the three months ended March 31, 2012, from $7.2 million in the three months ended March 31, 2011. This increase was primarily due to additional depreciation expense in the three months ended March 31, 2012 related to increased property and equipment balances between periods, primarily related to our expanded station network.

 

Interest expense, net.   Interest expense, net, increased by $2.9 million to $3.7 million for the three months ended March 31, 2012, up from $0.8 million for the three months ended March 31, 2011. This increase was primarily the result of an increase in interest expense related to the $200 million of convertible notes we issued in July and August of 2011. (See note 13 to our condensed consolidated financial statements for a description of our outstanding debt).

 

Other income, net.   Other income, net, increased by $0.2 million to $0.8 million for the three months ended March 31, 2012, compared to $0.6 million for the three months ended March 31, 2011. This increase was primarily due to foreign currency exchange rate changes between periods on our IMW purchase notes.

 

Income from equity method investment.   During the first quarter of 2012, we recorded $0.1 million equity income of our 49% interest in our Peruvian joint venture, compared to $0.2 million during the first quarter of 2011.

 

Income of noncontrolling interest.   During the three months ended March 31, 2012, we recorded $0.1 million for the noncontrolling interest in the net income of DCEMB, compared to $0.3 million for the noncontrolling interest in the net income of DCEMB for the three months ended March 31, 2011. The noncontrolling interest represents the 30% interest in our joint venture partner.

 

Seasonality and Inflation

 

To some extent, we experience seasonality in our results of operations. Natural gas vehicle fuel amounts consumed by some of our customers tends to be higher in summer months when buses and other fleet vehicles use more fuel to power their air conditioning systems. Natural gas commodity prices tend to be higher in the fall and winter months due to increased overall demand for natural gas for heating during these periods.

 

Since our inception, inflation has not significantly affected our operating results. However, costs for construction, repairs, maintenance, electricity and insurance are all subject to inflationary pressures and could affect our ability to maintain our stations adequately, build new stations, build new LNG plants and expand our existing facilities or materially increase our operating costs.

 

Liquidity and Capital Resources

 

We require cash to fund our operating expenses and working capital requirements, including outlays for the construction of new fueling stations, construction of LNG production facilities, the purchase of new LNG tanker trailers, investment in RNG production, mergers and acquisitions, the financing of natural gas vehicles for our customers and general corporate purposes, including making deposits to support our derivative activities, geographic expansion (domestically and internationally), expanding our sales and marketing activities, support of legislative and regulatory initiatives and for working capital for our expansion. Our principal sources of liquidity are cash on hand, cash provided by operating activities and cash provided by financing activities.

 

Liquidity

 

Cash used in operating activities was $15.1 million for the three months ended March 31, 2012, compared to cash provided by operating activities of $9.9 million for the three months ended March 31, 2011. The decrease in operating cash flow resulted primarily from higher selling, general and administrative expense and interest charges in the three month period ended March 31, 2012, coupled with decreases due to changes in working capital balances due to timing differences related to various cash flows

 

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between periods.  The biggest change between periods resulted from our collection of a full year of 2010 VETC revenue ($16.0 million) in the first quarter of 2011 as the legislation for VETC was reinstated in the fourth quarter of 2010 and made retroactive to January 1, 2010, but not filed for and received until the first quarter of 2011.  The legislation for VETC expired on December 31, 2011.

 

Cash used in investing activities was $33.9 million for the three months ended March 31, 2012, compared to $40.6 million for the three months ended March 31, 2011. Our purchases of property and equipment were $38.9 million during the first three months of 2012, and $10.8 million during the first three months of 2011. The increase was primarily related to our build-out of ANGH.  We made additional investments in The Vehicle Production Group, LLC (“VPG”), a company producing a CNG taxi and a paratransit vehicle, during the first three months of 2011 totaling $1.5 million, compared to zero during the first three months of 2012. During the first quarter of 2011, we invested $1.2 million 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. Also during the first quarter of 2011, as part of the DCEMB bond offering, we placed $27.1 million of cash into restricted accounts to be used for the capital and operating expenses of DCEMB. In the first quarter of 2012, we used $9.6 million of our long-term restricted cash to fund the construction of LNG stations.

 

Cash provided by financing activities for the three months ended March 31, 2012 was $0.5 million, compared to $28.3 million for the three months ended March 31, 2011. This decrease is primarily due to the DCEMB bond offering of $40.2 million for the use in the expansion of the landfill gas processing facility owned by DCEMB that closed on March 31, 2011.  This decrease was offset by a $9.7 million reduction in capital lease and debt payments between periods.  During the three months ended March 31, 2011, we paid of our Facility B Loan with $9.9 million of the proceeds we received from the DCEMB bond offering.  We also received net proceeds of $5.9 million from the exercise of employee stock options in the three months ended March 31, 2012, compared to $0.4 million for the three months ended March 31, 2011.

 

Our financial position and liquidity are, and will be, influenced by a variety of factors, including our ability to generate cash flows from operations, deposits and margin calls on our futures positions, the level of any outstanding indebtedness and the interest we are obligated to pay on this indebtedness, our capital expenditure requirements (which consist primarily of station construction, LNG plant construction costs, RNG plant construction costs and the purchase of LNG tanker trailers and equipment) and any merger or acquisition activity.

 

Sources of Cash

 

Historically, our principal sources of liquidity have consisted of cash provided by operations and financing activities. At March 31, 2012, we had total cash and cash equivalents of $190.7 million, compared to $238.1 million at December 31, 2011.

 

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

 

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

 

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

 

Capital Expenditures

 

Our business plan calls for approximately $188.9 million in capital expenditures from April 1, 2012 through the end of 2012, primarily related to construction of new fueling stations, including stations along ANGH, expanding our California LNG plant, expansion and construction of landfill gas processing plants, and the purchase of LNG trailers. We may also elect to invest additional amounts in companies or assets in the natural gas fueling infrastructure, services and production industries, including RNG production. We will need to raise additional capital as necessary to fund any capital expenditures or investments that we cannot fund through available cash or cash generated by operations. The timing and necessity of any future capital raises will depend on our rate of new station construction and potential merger or acquisition activity. We may not be able to raise capital on terms that are favorable to existing stockholders or at all. Any inability to raise capital may impair our ability to invest in new stations, develop natural gas fueling infrastructure and invest in strategic transactions or acquisitions and may reduce the ability of our business to grow and generate increased revenues.

 

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Off-Balance Sheet Arrangements

 

At March 31, 2012, we had the following off-balance sheet arrangements that had, or are reasonably likely to have, a material effect on our financial condition:

 

·                   outstanding surety bonds for construction contracts and general corporate purposes totaling $80.0 million,

 

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

 

·                   operating leases where we are the lessee,

 

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

 

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

 

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

 

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

 

We have entered into operating lease arrangements for certain equipment and for our office and field operating locations in the ordinary course of business. The terms of our leases expire at various dates through 2018. Additionally, in November 2006, we entered into a ground lease for 36 acres in California on which we built our California LNG liquefaction plant. The lease is for an initial term of thirty years and requires payments of $230 per year, plus up to $130 per year for each 30 million gallons of production capacity utilized, subject to future adjustment based on consumer price index changes. We must also pay a royalty to the landlord for each gallon of LNG produced at the facility, as well as a fee for certain other services that the landlord will provide.

 

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

 

Item 3.—Quantitative and Qualitative Disclosures about Market Risk

 

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

 

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

 

Natural gas costs represented 22% (or 32% excluding BAF, IMW and Northstar) of our cost of sales for 2011 and 19% (or 35% excluding BAF, IMW and Northstar) of our cost of sales for the three months ended March 31, 2012. Prices for natural gas over the twelve-year and three month period from December 31, 1999 through March 31, 2012, based on the NYMEX daily futures data, have ranged from a low of $1.65 per Mcf to a high of $19.38 per Mcf. At March 31, 2011, the NYMEX index price of natural gas was $2.41 per Mcf.

 

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

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

 

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

 

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

 

We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to the futures contracts we hold as of March 31, 2012 to hedge the fixed price component of certain supply contracts. If the price of natural gas were to fluctuate (increase or decrease) by 10% from the price quoted on NYMEX on March 31, 2012 ($2.41 per Mcf), we could expect a corresponding fluctuation in the value of the contracts of approximately $0.1 million.

 

Foreign exchange rate risk.   Because we have foreign operations, we are exposed to foreign currency exchange gains and losses. Since the functional currency of our foreign operations is in their local currency, the currency effects of translating the financial statements of those foreign subsidiaries, which operate in local currency environments, are included in the accumulated other comprehensive income (loss) component of consolidated equity and do not impact earnings. However, foreign currency transaction gains and losses not in our subsidiaries’ functional currency do impact earnings and resulted in approximately $0.1 million of gains in the three months ended March 31, 2012. During the three months ended March 31, 2012, our primary exposure to foreign currency rates related to our Canadian operations that had certain outstanding notes payable denominated in the United States dollar which were not hedged.

 

We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to our monetary transactions denominated in a foreign currency. If the exchange rate on these assets and liabilities were to fluctuate by 10% from the rate as of March 31, 2012, we would expect a corresponding fluctuation in the value of the assets and liabilities of approximately $4.3 million.

 

Item 4.—Controls and Procedures

 

Disclosure Controls and Procedures

 

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

 

Changes in Internal Control over Financial Reporting

 

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

 

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

 

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PART II.—OTHER INFORMATION

 

Item 1.—Legal Proceedings

 

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

 

Item 1A.—Risk Factors

 

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

 

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

 

For the three month period ended March 31, 2012, we incurred pre-tax losses of $31.5 million, which included derivative loss of $13.5 million related to marking to market the value of our Series I warrants. In 2009, 2010 and 2011, we incurred pre-tax losses of $33.4 million, $4.2 million, and $48.2 million, respectively. Our loss for 2009 includes $17.4 million of derivative losses related to marking to market the value of our Series I warrants; our loss for 2010 was decreased by a derivative gain of $10.3 million on our Series I warrants; and our loss for 2011 includes a $2.7 million derivative gain. During 2009, 2010 and 2011, our losses were substantially decreased by our receipt of approximately $15.5 million, $16.0 million, and $17.9 million of revenue from federal fuel tax credits, respectively. The program under which we received such credits expired on December 31, 2011. To build our business and improve our financial performance, we must continue to invest in developing the natural gas vehicle fuel market and offer our customers compelling natural gas fuel prices. If we do not achieve or maintain profitability that can be sustained in the absence of federal fuel tax credits, our business will suffer and the price of our common stock may drop. In addition, if the price of our common stock increases during future periods when our Series I warrants are outstanding, we may be required to recognize material losses based on the valuation of the outstanding Series I warrants.

 

A material portion of our historical revenues are associated with a federal fuel excise tax credit that expired on December 31, 2011.

 

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

 

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

 

Our business plan calls for us to construct ANGH, a network of LNG truck fueling stations on interstate highways and in major metropolitan areas that we expect to initially consist of approximately 150 stations. Building America’s Natural Gas Highway requires a significant commitment of capital and other resources, and our ability to successfully execute our plan faces substantial risks, including:

 

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

 

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

 

·                   Development of ANGH will require substantial amounts of capital, which may not be available on terms favorable to us or at all;

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

We will be required to raise debt or equity capital to fund the growth of our business. At March 31, 2012, we had total cash and cash equivalents of $190.7 million and short-term investments of $37.9 million, and we expect to receive an additional $50.0 million in June 2012 pursuant to the terms of our Loan Agreement with Chesapeake NG Ventures Corporation. Our business plan calls for approximately $188.9 million in capital expenditures from April 1, 2012 through the end of 2012. We may also require capital for unanticipated expenses, mergers and acquisitions and strategic investments. In addition, we have committed to significant future payments that we will be required to make in connection with our acquisitions of IMW and Northstar. At March 31, 2012, our future payments for IMW and Northstar totaled $32.5 million and $6.8 million, respectively. We are also obligated to pay up to $40.0 million as additional consideration related to our IMW acquisition if certain performance measurements of IMW are met.

 

Equity or debt financing options may not be available on terms favorable to us or at all. Additional sales of our common stock or securities convertible into our common stock will dilute existing stockholders and may result in a decline in our stock price. We may also pursue debt financing options including, but not limited to, equipment financing, the sale of convertible promissory notes or commercial bank financing. If we are unable to obtain debt or equity financing in amounts sufficient to fund any unanticipated expenses, capital expenditures, mergers, acquisitions or strategic investments, we will be forced to suspend or curtail these capital expenditures or postpone or delay potential acquisitions or other strategic transactions, which would harm our business, results of operations, and future prospects.

 

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

 

During July and August, 2011, we issued $200.0 million of debt securities and agreed to issue an additional $50.0 million of debt securities in each of June 2012 and June 2013. Such debt securities bear interest at the rate of 7.5% per annum. The entire principal balance of the debt securities issued in July 2011 is due and payable in July 2018, and the entire principal balance of the debt securities we issued in August 2011 is due and payable in August 2016. We may repay the debt securities in common stock or cash. We expect our interest payment obligations under the debt securities to be approximately $16.9 million for the year ending December 31, 2012 (such amount includes the interest that will be due on an additional $50 million of debt securities we anticipate issuing in June 2012). In future periods, we may not have sufficient capital resources to enable us to fulfill our payment obligations to the holders of our debt securities. If we are unable to make scheduled payments or comply with the other provisions of the documents relating to the debt securities, the holders of such debt securities may be permitted under certain circumstances to accelerate the maturity of the debt securities and exercise other remedies provided for in the securities and under applicable law. An acceleration of the maturity of the debt securities that is not rescinded would have a material adverse effect on our company.

 

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

 

Our business is influenced by tax credits, rebates and similar federal, state and local government incentives that promote the use of natural gas as a vehicle fuel in the United States. The federal income tax credit that was available to offset 50% to 80% of the incremental cost of purchasing new or converted natural gas vehicles expired on December 31, 2010. The continued absence of these vehicle tax credits could have a detrimental effect on the natural gas vehicle and fueling industry, including sales at our wholly owned subsidiary, BAF, and adversely affect our results of operations and financial performance. If federal incentives are not reinstated or extended and if new incentives are not passed, fewer natural gas vehicles may be sold and used and our revenue and financial performance may be adversely affected. Furthermore, the failure of certain federal, state or local government incentives which promote the use of natural gas as a vehicle fuel to pass into law could result in a negative perception by the market generally and a decline in the market price of our common stock. In addition, if grant funds are no longer available under existing government programs for the purchase and construction of natural gas vehicles and stations, the purchase of natural gas vehicles and station construction could slow and our business and results of operations may be adversely affected. Continued reduction in tax revenues associated with high unemployment rates, economic recession or slow-down could result in a significant reduction in funds available for government grants that support vehicle conversion and station construction, which could impair our ability to grow our business.

 

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

 

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

 

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

 

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

 

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

 

Limited availability of natural gas vehicles and engine sizes restricts their wide scale introduction and narrows our potential customer base. Original equipment manufacturers produce a small number of natural gas engines and vehicles in the U.S. and Canadian markets, and they may not make adequate investments to expand their natural gas engine and vehicle product lines. The technology used in some of the heavy duty vehicles that run on LNG is also relatively new and has not been previously deployed or used in large numbers of vehicles. As a result, these vehicles may require servicing and further technology refinements to address performance issues that may occur as vehicles are deployed in large numbers and are operated under strenuous conditions. If heavy duty LNG truck purchasers are not satisfied with truck performance, additional heavy-duty truck engine manufacturers do not enter the market for LNG engines, or LNG engines are not otherwise developed, produced and adopted in greater numbers, our ANGH investments and LNG fueling business may be significantly impaired, which would adversely affect our financial performance. Due to the limited supply of natural gas vehicles, our ability to promote natural gas vehicles and our natural gas fuel sales may be restricted, even if there is demand.

 

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

 

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

 

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

 

In the recent past, the price of natural gas has been volatile, and this volatility may continue. From the end of 1999 through March 31, 2012, the price for natural gas, based on the NYMEX daily futures data, ranged from a low of $1.65 per Mcf to a high of $19.38 per Mcf. At March 31, 2012, the NYMEX index price for natural gas was $2.41 per Mcf. Increased natural gas prices affect the cost to us of natural gas and will adversely impact our operating margins in cases where we have committed to sell natural gas at a fixed price without an effective futures contract in place that fully mitigates the price risk or where we otherwise cannot pass the increased costs on to our customers. In addition, higher natural gas prices may cause CNG and LNG to cost as much as or more than gasoline and diesel generally, which would adversely impact the adoption of CNG and LNG as a vehicle fuel and consequently our business. Conversely, lower natural gas prices reduce our revenues due to the fact that in a significant amount of our customer agreements, the commodity cost is passed through to the customer. Among the factors that can cause price fluctuations in natural gas prices are changes in domestic and foreign supplies of natural gas, domestic storage levels, crude oil prices, the price difference between crude oil and natural gas, price and availability of alternative fuels, weather conditions, negative publicity surrounding drilling techniques, level of consumer demand, economic conditions, price of foreign natural gas imports, and domestic and foreign governmental regulations and political conditions. In particular, there have been recent efforts to place new regulatory requirements on the production of natural gas by hydraulic fracturing of shale gas reservoirs. Hydraulic fracturing of shale gas reservoirs has resulted in a substantial increase in the proven natural gas reserves in the United States, and any changes in regulations that make it more expensive or unprofitable to produce natural gas through hydraulic fracturing could lead to increased natural gas prices.

 

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

 

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

 

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

 

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

 

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

 

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

 

Our global operations expose us to additional risk and uncertainties.

 

We have operations in a number of countries, including the United States, Canada, China, Colombia, Bangladesh and Peru. In addition to the other risks described herein, our global operations may be subject to risks and uncertainties that may limit our ability to operate our business. Our natural gas compression equipment is primarily manufactured in Canada and sold globally, which exposes us to a number of risks that can arise from international trade transactions, local business practices and cultural considerations, including:

 

·                   compliance with the United States Foreign Corrupt Practices Act;

 

·                   political unrest, terrorism and economic and financial instability;

 

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

 

·                   import-export regulations;

 

·                   difficulties in enforcing agreements and collecting receivables;

 

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

 

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

 

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

 

·                   limited intellectual property protection;

 

·                   longer payment cycles by international customers;

 

·                   currency exchange fluctuations;

 

·                   inadequate local infrastructure and disruptions of service from utilities or telecommunications providers, including electricity shortages;

 

·                   potentially adverse tax consequences; and

 

·                   differing employment practices and labor issues.

 

We also face risks associated with currency exchange and convertibility, inflation and repatriation of earnings as a result of our foreign operations. In some countries, economic, monetary and regulatory factors could affect our ability to convert funds to United States dollars or move funds from accounts in these countries. We are also vulnerable to appreciation or depreciation of foreign currencies against the United States dollar. We do not engage in currency hedging activities to limit the risks of currency fluctuations.

 

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

 

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

 

A significant portion of the purchase price of IMW was allocated to goodwill and a write-off of all or part of this goodwill could adversely affect our operating results.

 

Under business combination accounting standards, we allocated the total purchase price of IMW to its net tangible assets and liabilities and intangible assets based on their fair values as of the date of the acquisition and recorded the excess of the purchase price over those values as goodwill. Our estimates of the fair value of the assets and liabilities of IMW were based upon certain assumptions, including assumptions about and anticipated attainment of new business, believed to be reasonable, but which are inherently uncertain. Pursuant to the applicable accounting standards, we initially allocated $45.0 million of the purchase price for IMW to goodwill. Our goodwill could be impaired if developments affecting the acquired compressor manufacturing operations or the markets in which IMW produces and/or sells compressors lead us to conclude that the cash flows we expect to derive from its manufacturing operations will be substantially reduced. An impairment of all or part of our goodwill could adversely affect our results of operations.

 

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

 

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

 

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

 

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

 

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

 

We have existing, and will continue to seek, long-term CNG and LNG station construction, maintenance and fuel sales contracts with various federal, state and local governmental bodies, which accounted for approximately 30% of our revenues for the three month period ended March 31, 2012 and approximately 59%, 42% and 33% of our annual revenues in 2009, 2010 and 2011, respectively. In addition to our normal business risks, our contracts with these government entities are often subject to unique risks, some of which are beyond our control. Long-term government contracts and related orders are subject to cancellation if appropriations for subsequent performance periods are not made. The termination of funding for a government program supporting any of our CNG or LNG operations could result in a loss of anticipated future revenues attributable to that program, which could have a negative impact on our operations. In addition, government entities with whom we contract are often able to modify, curtail or terminate contracts with us without prior notice at their convenience, and are only liable for payment for work done and commitments made at the time of termination. Modification, curtailment or termination of significant contracts could have a material adverse effect on our results of operations and financial condition.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Our ability to obtain LNG is restricted by fragmented and limited production of LNG.

 

Production of LNG in the United States is fragmented and limited. It may be difficult for us to obtain LNG without interruption and near our current or target markets at competitive prices or at all. If LNG liquefaction plants we own, or if any of those from which we purchase LNG, are damaged by severe weather, earthquake or other natural disaster, or otherwise experience prolonged downtime, or if new LNG liquefaction plants are not built, our LNG supply will be restricted. One of the suppliers from

 

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whom we obtain LNG has experienced unscheduled plant shut downs and has been unable to maintain minimum production levels on a consistent basis, which has caused us to incur additional costs to obtain LNG from other sources. If we are unable to supply enough of our own LNG or purchase it from third parties to meet customer demand, we may be liable to our customers for penalties. In addition, the execution of our business plan will require substantial growth in the available LNG supply across the United States, and if this supply is unavailable, it will constrain our ability to increase the market for LNG fuel, including supplying LNG fuel to heavy duty truck customers, and will adversely affect our investments in ANGH. If we experience an LNG supply interruption or LNG demand that exceeds available supply, or if we have difficulty entering or maintaining relationships with contract carriers to deliver LNG on our behalf, our ability to expand LNG sales to new customers will be limited, our relationships with existing customers may be disrupted, and our results of operations may be adversely affected. Furthermore, because transportation of LNG is relatively expensive, if we are required to supply LNG to our customers from distant locations and cannot pass these costs through to our customers, our operating margins will decrease on those sales due to our increased transportation costs.

 

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

 

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

 

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

 

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

 

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

 

From 2005 to 2008, we sold and delivered approximately 30% of our total gasoline gallon equivalents of CNG and LNG under contracts that provided a fixed price or a price cap to our customers over terms typically ranging from one to three years, and in some cases up to five years. Effective January 1, 2007, we no longer offer contracts with a price cap to our customers, though, from time to time we still enter into contracts with various customers to sell CNG or LNG at fixed prices. At any given time, the market price of natural gas may rise and our obligations to sell fuel under fixed price contracts may be at prices lower than our fuel purchase price if we do not have effective futures contracts in place. This circumstance has in the past and may again in the future compel us to sell fuel at a loss, which would adversely affect our results of operations and financial condition. Commencing with the adoption of our revised natural gas hedging policy in February 2007, our policy has been to purchase futures contracts to hedge our exposure to natural gas price variability related to our fixed price contracts. Such contracts, however, may not be available or we may not have sufficient financial resources to secure such contracts. In addition, under our hedging policy, we may reduce or remove futures contracts we have in place related to these contracts if such disposition is approved in advance by our board of directors and derivative committee. If we are not effectively economically hedged with respect to our fixed price contracts, we will lose money in connection with those contracts during periods in which natural gas prices increase above the prices of natural gas included in our customers’ contracts. As of March 31, 2012, we were economically hedged with respect to our fixed price contracts with our customers.

 

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

 

Our purchase of futures contracts can result in substantial losses under various circumstances, including if we do not accurately estimate the volume requirements under our fixed price customer contracts when determining the volumes included in the futures contracts we purchase, or we elect to purchase a futures contract in connection with a bid proposal and ultimately we are not awarded the entire contract or our customer does not fully perform its obligations under the awarded contract. We also could incur significant losses if a counterparty does not perform its obligations under the applicable futures arrangement, the futures arrangement is economically imperfect or ineffective, or our futures policies and procedures are not properly followed or do not work as planned. Furthermore, we cannot be assured that the steps we take to monitor our futures activities will detect and prevent violations of our risk management policies and procedures.

 

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

 

We are required to maintain a margin account to cover losses related to our natural gas futures contracts. Futures contracts are valued daily, and if our contracts are in loss positions at the end of a trading day, our broker will transfer the amount of the losses from our margin account to a clearinghouse. If at any time the funds in our margin account drop below a specified maintenance level, our broker will issue a margin call that requires us to restore the balance. Payments we make to satisfy margin calls will reduce our cash reserves, adversely impact our liquidity and may also adversely impact our ability to expand our business. Moreover, if we are unable to satisfy the margin calls related to our futures contracts, our broker may sell these contracts to restore the margin requirement at a substantial loss to us. As of March 31, 2012, we had $3.6 million on deposit related to our futures contracts.

 

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

 

We account for our futures activities under the relevant derivative accounting guidance, which requires us to value our futures contracts at fair market value in our financial statements. Prior to June 2008, our futures contracts did not qualify for hedge accounting, and therefore we have recorded any changes in the fair market value of these contracts directly in our consolidated statements of operations in the line item “derivative (gains) losses” along with any realized gains or losses during the period. At March 31, 2012, all of our futures contracts qualified for hedge accounting. To the extent that all or some of our futures contracts do not qualify for hedge accounting, we could incur significant increases and decreases in our net income (loss) and stockholders’ equity in the future based on fluctuations in the market value of our futures contracts from quarter to quarter. We had no derivative gains or losses related to our natural gas futures contracts for the year ended December 31, 2011 and for the three months ended March 31, 2012. Any negative fluctuations may cause our stock price to decline due to our failure to meet or exceed the expectations of securities analysts or investors.

 

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

 

California has adopted legislation, AB 32, which calls for a cap on greenhouse gas emissions throughout California and a statewide reduction to 1990 levels by 2020 and an additional 80% reduction below 1990 levels by 2050. Other states and the federal government are considering passing measures to regulate and reduce greenhouse gas emissions. Any of these regulations, when and if implemented, may regulate the greenhouse gas emissions produced by our LNG production plants in California and Texas or our CNG and LNG fueling stations and require that we obtain emissions credits or invest in costly emissions prevention technology. We cannot currently estimate the potential costs associated with federal or state regulation of greenhouse gas emissions from our LNG plants or CNG and LNG stations, and these unknown costs are not contemplated by our customer agreements. These unanticipated costs may have a negative impact on our financial performance and may impair our ability to fulfill customer contracts at an operating profit.

 

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

 

Natural gas fueling operations and vehicle conversions entail inherent risks, including equipment defects, malfunctions and failures and natural disasters, which could result in uncontrollable flows of natural gas, fires, explosions and other damages. For example, operation of LNG pumps requires special training and protective equipment because of the extreme low temperatures of LNG. LNG tanker trailers have also in the past been, and may in the future be, involved in accidents that result in explosions, fires and other damage. Improper refueling of LNG vehicles can result in venting of methane gas, which is a potent greenhouse gas, and LNG related methane emissions may in the future be regulated by the EPA or by state regulations. Additionally, CNG fuel tanks, if damaged or improperly maintained or installed, may rupture and the contents of the tank may rapidly decompress and result in death or injury. These risks may expose us to liability for personal injury, wrongful death, property damage, pollution and other environmental damage. We may incur substantial liability and cost if damages are not covered by insurance or are in excess of policy limits. If CNG or LNG vehicles are perceived to be unsafe, it will harm our growth and negatively affect BAF’s ability to sell converted CNG vehicles, which would impair our financial performance.

 

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

 

We loan to certain qualifying customers a portion of, and occasionally up to 100% of, the purchase price of natural gas vehicles. We may also lease vehicles to customers in the future. There are risks associated with providing financing or leasing that could cause us to lose money. Some of these risks include: the equipment financed consists mostly of vehicles that are mobile and

 

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easily damaged, lost or stolen, there is a risk the borrower may default on payments, we may not be able to bill properly or track payments in adequate fashion to sustain growth of this service, and the amount of capital available to us is limited and may not allow us to make loans required by customers. Some of our customers, such as taxi owners, may depend on the CNG vehicles that we finance or lease to them as their sole source of income, which may make it difficult for us to recover the collateral in a bankruptcy proceeding. As of March 31, 2012, we had $6.8 million outstanding in loans provided to customers to finance natural gas vehicle purchases.

 

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

 

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

 

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

 

We may not be successful in developing or expanding our RNG business.

 

In November 2010, we announced that we entered into an agreement to develop a pipeline quality RNG project at a Republic Services owned landfill outside of Detroit, Michigan (the “Michigan Plant”). We are also in the process of expanding operations at our RNG production facility at the McCommas Bluff landfill outside of Dallas, Texas. In addition, we are seeking to increase our RNG business by pursuing additional projects. RNG production represents a new area of investment and operations for us, and we may not be successful in developing these projects and generating a financial return from our investment. Historically, projects that produce pipeline quality RNG have often failed due to the volatile prices of conventional natural gas, unpredictable RNG production levels and technological difficulties and costs associated with operating the production facilities. Our ability to succeed in expanding our McCommas Bluff project and developing the Michigan Plant and other projects we may secure in the future depends on our ability to obtain necessary financing, successfully manage the construction and operation of RNG production facilities and our ability to sell and market the RNG at substantial premiums to recent conventional natural gas prices. If we are unsuccessful in obtaining necessary financing or managing the construction and operation of our RNG production facilities, or if we are unable to sell and market RNG at a substantial premium to conventional natural gas prices, our business and financial results may be materially and adversely affected. In addition, the CEC has suspended the renewable portfolio standard (“RPS”) eligibility for certifying power plants that generate electricity from RNG.  Unless lifted or modified, this suspension will limit our ability to sell RNG produced by the Michigan Plant and other projects we may develop to California utilities. If we cannot sell RNG we produce to California utilities for use as an RPS compliant fuel, we may not be able to obtain premium prices for RNG. In the absence of state and federal programs that support premium prices for RNG, we will be unable to generate profit and financial return from these investments, and our financial results could be materially and adversely affected.

 

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

 

In August 2008, we acquired our 70% interest in DCE, which owns 100% of DCEMB. DCEMB is a party to a 15-year gas sale agreement with Shell for the sale to Shell of specified levels of RNG produced by DCEMB’s landfill gas processing facility. DCEMB may not be able to produce or sell up to the maximum volumes called for under the agreement or produce RNG that meets the relevant pipeline specification. DCEMB’s ability to produce such volumes of RNG depends on a number of factors beyond DCEMB’s control, including, but not limited to, the availability and composition of the landfill gas that is collected, successful permitting, the operation of the landfill by the City of Dallas, the reliability of the processing facility’s critical equipment and weather conditions. The DCEMB facility is subject to periods of reduced production or non-production due to upgrades, maintenance, repairs and other factors. For example, as part of an operational upgrade in March 2009, the facility was shut down for approximately one month. Also, on June 12, 2009, the facility was taken offline for repairs that were completed on July 2, 2009, and the facility was taken offline for upgrades from September 20, 2010 until September 25, 2010. Severe

 

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winter weather in Texas resulted in power outages and broken equipment in February 2011, resulting in a week of down time and an extended period during which the plant operated at half capacity. Further, production has been negatively affected by the recent severe drought and high temperature conditions in Texas. Future operational upgrades, including planned expansion of the plant, or other complications in the operations of the facility could require shutdowns, and accordingly, DCEMB’s revenues may fluctuate from quarter to quarter.

 

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

 

Our quarterly results of operations have historically experienced significant fluctuations. Our net losses (income) were approximately $6.5 million, $6.4 million, $18.5 million, $1.9 million, $24.4 million, $(9.9) million, $1.8 million, $(13.8) million, $9.8 million, $5.6 million, $11.4 million, $(20.9), and $31.9 million for the three months ended March 31, 2009, June 30, 2009, September 30, 2009, December 31, 2009, March 31, 2010, June 30, 2010, September 30, 2010, December 31, 2010, March 31, 2011, June 30, 2011, September 30, 2011, December 31, 2011, and March 31, 2012, respectively. Our quarterly results may fluctuate significantly as a result of a variety of factors, many of which are beyond our control. In particular, if our stock price increases or decreases in future periods during which our Series I warrants are outstanding, we will be required to recognize corresponding losses or gains related to the valuation of the Series I warrants that could materially impact our results of operations. If our quarterly results of operations fall below the expectations of securities analysts or investors, the price of our common stock could decline substantially. Fluctuations in our quarterly results of operations may be due to a number of factors, including, but not limited to, our ability to increase sales to existing customers and attract new customers, the addition or loss of large customers, construction cost overruns, downtime at our facilities (including any shutdowns of DCEMB’s landfill gas processing facility), the amount and timing of operating costs, unanticipated expenses, capital expenditures related to the maintenance and expansion of our business, operations and infrastructure, our debt service obligations, changes in the price of natural gas, changes in the prices of CNG and LNG relative to gasoline and diesel, changes in our pricing policies or those of our competitors, fluctuation in the value of our natural gas futures contracts, the costs related to the acquisition of assets or businesses, regulatory changes, and geopolitical events such as war, threat of war or terrorist actions. Investors in our stock should not rely on the results of one quarter as an indication of future performance as our quarterly revenues and results of operations may vary significantly in the future. Therefore, period-to-period comparisons of our operating results may not be meaningful.

 

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

 

As of March 31, 2012, there were 86,329,061 shares of our common stock outstanding, 10,903,234 shares underlying outstanding options, 2,130,682 shares underlying outstanding warrants (all of which were sold in our registered direct offering that closed in November 2008), 13,164,557 shares underlying the convertible notes we issued in July and August 2011 and 1,420,000 restricted stock units.  All of our outstanding shares are eligible for sale in the public market, subject in certain cases to the requirements of Rule 144 of the Securities Act. Also, shares subject to outstanding options, warrants and convertible notes are eligible for sale in the public market to the extent permitted by the provisions of various option, warrant and convertible note agreements and Rule 144, or if such shares have been registered for resale under the Securities Act (8,999,999 shares underlying convertible notes we issued in August 2011 have been registered for resale under the Securities Act). If these shares are sold, or if it is perceived that they will be sold in the public market, the trading price of our common stock could decline.

 

Further, as of March 31, 2012, 16,539,720 shares of our stock held by our co-founder and board member T. Boone Pickens are subject to pledge agreements with banks. Should one or more of the banks be forced to sell the shares subject to the pledge, the trading price of our stock could also decline. In addition, a number of our directors and executive officers have entered into Rule 10b5-1 Sales Plans with a broker to sell shares of our common stock that they hold or that may be acquired upon the exercise of stock options. Sales under these plans will occur automatically without further action by the director or officer once the price and/or date parameters of the particular selling plan are achieved. As of March 31, 2012, 685,618 shares in the aggregate were subject to future sales by our named executive officers and directors under these selling plans. All sales of common stock under the plans will be reported through appropriate filings with the SEC.

 

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

 

As of March 31, 2012, T. Boone Pickens and affiliates (including Madeleine Pickens, his wife) owned in the aggregate approximately 22.7% of our outstanding shares of common stock. As a result, Mr. Pickens will be able to influence or control matters requiring approval by our stockholders, including the election of directors and the approval of mergers, acquisitions or other extraordinary transactions. Mr. Pickens may have interests that differ from yours and may vote in a way with which you disagree and that may be adverse to your interests. This concentration of ownership may have the effect of delaying, preventing or deterring a change of control of our company, could deprive our stockholders of an opportunity to receive a premium for their stock as part of a sale of our company, and might ultimately affect the market price of our stock. Conversely, this concentration may facilitate a change in control at a time when you and other investors may prefer not to sell.

 

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

 

None.

 

Item 3.—Defaults upon Senior Securities

 

None.

 

Item 4.—Mine Safety Disclosures

 

None.

 

Item 5.—Other Information

 

None.

 

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Item 6.—Exhibits

 

(a)                                  Exhibits

 

10.65*

 

First Amendment to Amended and Restated Employment Agreement, dated February 17, 2012, between the Registrant and Andrew J. Littlefair.

 

 

 

10.66*

 

First Amendment to Amended and Restated Employment Agreement, dated February 17, 2012, between the Registrant and Richard R. Wheeler.

 

 

 

10.67*

 

First Amendment to Amended and Restated Employment Agreement, dated February 17, 2012, between the Registrant and Mitchell W. Pratt.

 

 

 

10.68*

 

First Amendment to Amended and Restated Employment Agreement, dated February 17, 2012, between the Registrant and James N. Harger.

 

 

 

10.69*

 

First Amendment to Employment Agreement, dated February 17, 2012, between the Registrant and Barclay F. Corbus.

 

 

 

31.1*

 

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

 

 

 

31.2*

 

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

 

 

 

32.1*

 

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

 

 

 

101†

 

The following materials from the Company’s Quarterly Report of Form 10-Q for the quarter ended March 31, 2012, formatted in XBRL (eXtensible Business Reporting Language):

 

 

 

 

 

(i) Condensed Consolidated Balance Sheets at December 31, 2011 and March 31, 2012;

 

 

(ii) Condensed Consolidated Statement of Operations for the Three Months Ended March 31, 2011 and 2012;

 

 

(iii) Condensed Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2011 and 2012;

 

 

(iv) Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2011 and 2012; and

 

 

(v) Notes to Condensed Consolidated Financial Statements, tagged as block of text.

 


*                  Filed herewith.

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

 

46



Table of Contents

 

SIGNATURE

 

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

 

 

CLEAN ENERGY FUELS CORP.

 

 

 

 

 

 

Date: May 7, 2012

By:

/s/ RICHARD R. WHEELER

 

 

Richard R. Wheeler

 

 

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

 

47


Exhibit 10.65

 

FIRST AMENDMENT TO

AMENDED AND RESTATED EMPLOYMENT AGREEMENT

 

Pursuant to Section 7(c) of the Amended and Restated Employment Agreement (the “Agreement”) dated December 31, 2008, by and between Clean Energy Fuels Corp., Inc., a Delaware corporation (the “Company”) and Andrew J. Littlefair, an individual (the “Executive”) (collectively, the “Parties”), the Parties hereby adopt the following amendment to the Agreement, to be effective as of the date specified below. Capitalized terms used herein and not otherwise defined shall have the meaning ascribed to such terms in the Agreement.  All other terms and conditions of the Agreement that are not modified below shall continue to remain in full force and effect.

 

The first sentence of Section 2 of the Agreement is restated in its entirety to read as follows:

 

“Employer agrees to employ Employee and Employee agrees to serve Employer, in accordance with the terms of this Agreement, for a term commencing on the Restatement Date and ending on December 31, 2015 (the “Term”).”

 

IN WITNESS WHEREOF , the Parties have caused this amendment to the Agreement to be duly executed, to be effective as of February 17, 2012.

 

 

“EMPLOYER”

 

 

 

CLEAN ENERGY FUELS CORP.,

 

a Delaware corporation

 

 

 

 

 

By:

/s/ Richard R. Wheeler

 

Name:

Richard R. Wheeler

 

Title:

Chief Financial Officer

 

 

 

 

 

 

“EMPLOYEE”

 

 

 

 

 

/s/ Andrew J. Littlefair

 

Andrew J. Littlefair

 


Exhibit 10.66

 

FIRST AMENDMENT TO

AMENDED AND RESTATED EMPLOYMENT AGREEMENT

 

Pursuant to Section 7(c) of the Amended and Restated Employment Agreement (the “Agreement”) dated December 31, 2008, by and between Clean Energy Fuels Corp., Inc., a Delaware corporation (the “Company”) and Richard R. Wheeler, an individual (the “Executive”) (collectively, the “Parties”), the Parties hereby adopt the following amendment to the Agreement, to be effective as of the date specified below. Capitalized terms used herein and not otherwise defined shall have the meaning ascribed to such terms in the Agreement.  All other terms and conditions of the Agreement that are not modified below shall continue to remain in full force and effect.

 

The first sentence of Section 2 of the Agreement is restated in its entirety to read as follows:

 

“Employer agrees to employ Employee and Employee agrees to serve Employer, in accordance with the terms of this Agreement, for a term commencing on the Restatement Date and ending on December 31, 2015 (the “Term”).”

 

IN WITNESS WHEREOF , the Parties have caused this amendment to the Agreement to be duly executed, to be effective as of February 17, 2012.

 

 

“EMPLOYER”

 

 

 

CLEAN ENERGY FUELS CORP.,

 

a Delaware corporation

 

 

 

 

 

 

By:

/s/ Andrew J. Littlefair

 

Name:

Andrew J. Littlefair

 

Title:

Chief Executive Officer

 

 

 

 

 

“EMPLOYEE”

 

 

 

 

 

/s/ Richard R. Wheeler

 

Richard R. Wheeler

 


Exhibit 10.67

 

FIRST AMENDMENT TO

AMENDED AND RESTATED EMPLOYMENT AGREEMENT

 

Pursuant to Section 7(c) of the Amended and Restated Employment Agreement (the “Agreement”) dated December 31, 2008, by and between Clean Energy Fuels Corp., Inc., a Delaware corporation (the “Company”) and Mitchell W. Pratt, an individual (the “Executive”) (collectively, the “Parties”), the Parties hereby adopt the following amendment to the Agreement, to be effective as of the date specified below. Capitalized terms used herein and not otherwise defined shall have the meaning ascribed to such terms in the Agreement.  All other terms and conditions of the Agreement that are not modified below shall continue to remain in full force and effect.

 

The first sentence of Section 2 of the Agreement is restated in its entirety to read as follows:

 

“Employer agrees to employ Employee and Employee agrees to serve Employer, in accordance with the terms of this Agreement, for a term commencing on the Restatement Date and ending on December 31, 2015 (the “Term”).”

 

IN WITNESS WHEREOF , the Parties have caused this amendment to the Agreement to be duly executed, to be effective as of February 17, 2012.

 

 

“EMPLOYER”

 

 

 

CLEAN ENERGY FUELS CORP.,

 

a Delaware corporation