Clean Energy Fuels Corp.
Clean Energy Fuels Corp. (Form: 10-Q, Received: 11/09/2012 15:53:00)

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 September 30, 2012

 

Commission File Number: 001-33480

 

CLEAN ENERGY FUELS CORP.

(Exact name of registrant as specified in its charter)

 

Delaware

 

33-0968580

(State or other jurisdiction of incorporation)

 

(IRS Employer Identification No.)

 

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

(Address of principal executive offices, including zip code)

 

(562) 493-2804

(Registrant’s telephone number, including area code)

 

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

 

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

 

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

 

Large accelerated filer  o

 

Accelerated filer  x

 

 

 

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

 

Smaller reporting company  o

 

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

 

As of October 29, 2012, there were 87,550,153 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

3

Item 1.—Financial Statements (Unaudited)

3

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

23

Item 3.—Quantitative and Qualitative Disclosures About Market Risk

37

Item 4.—Controls and Procedures

38

PART II.—OTHER INFORMATION

38

Item 1.—Legal Proceedings

38

Item 1A.—Risk Factors

38

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

49

Item 3.—Defaults upon Senior Securities

49

Item 4.— Mine Safety Disclosures

49

Item 5.—Other Information

49

Item 6.—Exhibits

49

 

2



Table of Contents

 

PART I.—FINANCIAL INFORMATION

 

Item 1.—Financial Statements (Unaudited)

 

Clean Energy Fuels Corp. and Subsidiaries

 

Condensed Consolidated Balance Sheets

 

As of December 31, 2011 and September 30, 2012

 

(Unaudited)

 

(In thousands, except share data)

 

 

 

December 31,
2011

 

September 30,
2012

 

Assets

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

238,125

 

$

149,068

 

Restricted cash

 

4,792

 

8,434

 

Short-term investments

 

33,329

 

29,660

 

Accounts receivable, net of allowance for doubtful accounts of $712 and $878 as of December 31, 2011 and September 30, 2012, respectively

 

56,455

 

65,993

 

Other receivables

 

19,601

 

24,171

 

Inventory, net

 

35,287

 

37,343

 

Prepaid expenses and other current assets

 

22,252

 

30,754

 

Total current assets

 

409,841

 

345,423

 

Land, property and equipment, net

 

257,463

 

376,012

 

Restricted cash

 

54,804

 

46,865

 

Notes receivable and other long-term assets

 

16,650

 

15,126

 

Investments in other entities

 

16,459

 

17,106

 

Goodwill

 

73,741

 

73,741

 

Intangible assets, net

 

102,103

 

97,873

 

Total assets

 

$

931,061

 

$

972,146

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Current portion of long-term debt and capital lease obligations

 

$

22,925

 

$

34,068

 

Accounts payable

 

36,668

 

38,131

 

Accrued liabilities

 

28,255

 

30,565

 

Deferred revenue

 

9,621

 

33,287

 

Total current liabilities

 

97,469

 

136,051

 

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

 

266,497

 

303,926

 

Other long-term liabilities

 

22,687

 

17,768

 

Total liabilities

 

386,653

 

457,745

 

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 87,232,094 shares at December 31, 2011 and September 30, 2012, respectively

 

9

 

9

 

Additional paid-in capital

 

741,650

 

771,135

 

Accumulated deficit

 

(199,559

)

(259,079

)

Accumulated other comprehensive loss

 

(1,216

)

(1,521

)

Total Clean Energy Fuels Corp. stockholders’ equity

 

540,884

 

510,544

 

Noncontrolling interest in subsidiary

 

3,524

 

3,857

 

Total stockholders’ equity

 

544,408

 

514,401

 

Total liabilities and stockholders’ equity

 

$

931,061

 

$

972,146

 

 

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 and Nine Months Ended September 30, 2011 and 2012

 

(Unaudited)

 

(In thousands, except share and per share data)

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2011

 

2012

 

2011

 

2012

 

Revenue:

 

 

 

 

 

 

 

 

 

Product revenues

 

$

64,237

 

$

82,720

 

$

184,292

 

$

206,201

 

Service revenues

 

7,845

 

8,739

 

22,244

 

28,734

 

Total revenue

 

72,082

 

91,459

 

206,536

 

234,935

 

Operating expenses:

 

 

 

 

 

 

 

 

 

Cost of sales:

 

 

 

 

 

 

 

 

 

Product cost of sales

 

48,853

 

67,392

 

139,591

 

162,985

 

Service cost of sales

 

3,901

 

3,839

 

10,591

 

12,662

 

Derivative gains:

 

 

 

 

 

 

 

 

 

Series I warrant valuation

 

(1,524

)

(5,692

)

(3,059

)

(1,085

)

Selling, general and administrative

 

20,140

 

30,557

 

59,823

 

83,323

 

Depreciation and amortization

 

7,554

 

9,047

 

22,396

 

26,098

 

Total operating expenses

 

78,924

 

105,143

 

229,342

 

283,983

 

Operating loss

 

(6,842

)

(13,684

)

(22,806

)

(49,048

)

Interest expense, net

 

(3,194

)

(4,314

)

(5,520

)

(11,337

)

Other income (expense), net

 

(2,450

)

1,914

 

(1,662

)

1,578

 

Income from equity method investments

 

99

 

152

 

474

 

315

 

Loss before income taxes

 

(12,387

)

(15,932

)

(29,514

)

(58,492

)

Income tax benefit (expense)

 

960

 

(277

)

2,872

 

(695

)

Net loss

 

(11,427

)

(16,209

)

(26,642

)

(59,187

)

Loss (income) of noncontrolling interest

 

73

 

(112

)

(84

)

(333

)

Net loss attributable to Clean Energy Fuels Corp.

 

$

(11,354

)

(16,321

)

$

(26,726

)

(59,520

)

Loss per share attributable to Clean Energy Fuels Corp.

 

 

 

 

 

 

 

 

 

Basic

 

$

(0.16

)

(0.19

)

$

(0.38

)

(0.69

)

Diluted

 

$

(0.16

)

(0.19

)

$

(0.38

)

(0.69

)

Weighted average common shares outstanding

 

 

 

 

 

 

 

 

 

Basic

 

70,364,202

 

87,006,024

 

70,255,311

 

86,441,196

 

Diluted

 

70,364,202

 

87,006,024

 

70,255,311

 

86,441,196

 

 

See accompanying notes to condensed consolidated financial statements.

 

4



Table of Contents

 

Clean Energy Fuels Corp. and Subsidiaries

 

Condensed Consolidated Statements of Comprehensive Income (Loss)

 

For the Three Months and Nine Months Ended September 30, 2011 and 2012

 

(Unaudited)

 

(In thousands)

 

 

 

Clean Energy Fuels Corp.

 

Noncontrolling Interest

 

Total

 

 

 

Three Months Ended
September 30,

 

Three Months Ended
September 30,

 

Three Months Ended
September 30,

 

 

 

2011

 

2012

 

2011

 

2012

 

2011

 

2012

 

Net income (loss)

 

$

(11,354

)

(16,321

)

$

(73

)

112

 

$

(11,427

)

(16,209

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other comprehensive income, net of tax:

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign currency translation adjustments

 

2,803

 

(1,941

)

 

 

2,803

 

(1,941

)

Unrealized gains on available-for sale securities

 

 

38

 

 

 

 

38

 

Unrecognized gains on derivatives

 

476

 

157

 

 

 

476

 

157

 

Total other comprehensive income, net of tax

 

3,279

 

(1,746

)

 

 

3,279

 

(1,746

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income (loss)

 

$

(8,075

)

(18,067

)

(73

)

112

 

(8,148

)

(17,955

)

 

 

 

Clean Energy Fuels Corp.

 

Noncontrolling Interest

 

Total

 

 

 

Nine Months Ended
September 30,

 

Nine Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2011

 

2012

 

2011

 

2012

 

2011

 

2012

 

Net income (loss)

 

$

(26,726

)

(59,520

)

$

84

 

333

 

$

(26,642

)

(59,187

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other comprehensive income, net of tax:

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign currency translation adjustments

 

2,105

 

(2,250

)

 

 

2,105

 

(2,250

)

Unrealized losses on available-for sale securities

 

 

(178

)

 

 

 

(178

)

Unrecognized gains on derivatives

 

1,689

 

2,123

 

 

 

1,689

 

2,123

 

Total other comprehensive income, net of tax

 

3,794

 

(305

)

 

 

3,794

 

(305

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income (loss)

 

$

(22,932

)

(59,825

)

$

84

 

333

 

$

(22,848

)

(59,492

)

 

See accompanying notes to condensed consolidated financial statements.

 

5



Table of Contents

 

Clean Energy Fuels Corp. and Subsidiaries

 

Condensed Consolidated Statements of Cash Flows

 

For the Nine Months Ended September 30, 2011 and 2012

 

(Unaudited)

 

(In thousands)

 

 

 

Nine Months Ended
September 30,

 

 

 

2011

 

2012

 

Cash flows from operating activities:

 

 

 

 

 

Net loss

 

$

(26,642

)

$

(59,187

)

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

 

 

 

 

 

Depreciation and amortization

 

22,396

 

26,098

 

Provision for doubtful accounts and notes

 

335

 

469

 

Derivative (gain) loss

 

(3,059

)

(1,085

)

Stock-based compensation expense

 

10,093

 

16,492

 

Amortization of debt issuance cost

 

2,060

 

352

 

Accretion of notes payable

 

238

 

1,523

 

Gain on contingent consideration for acquisitions

 

(2,554

)

(3,994

)

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

 

 

 

 

 

Accounts and other receivables

 

15,855

 

(10,123

)

Inventory

 

(11,943

)

(1,498

)

Margin deposits on futures contracts

 

2,981

 

3,000

 

Prepaid expenses and other assets

 

(13,130

)

(14,375

)

Accounts payable

 

(5,878

)

(2,409

)

Accrued expenses and other

 

3,251

 

25,817

 

Net cash provided by (used in) operating activities

 

(5,997

)

(18,920

)

Cash flows from investing activities:

 

 

 

 

 

Purchases of short-term investments

 

 

(24,015

)

Maturities of short-term investments

 

 

27,506

 

Purchases of property and equipment

 

(39,869

)

(132,840

)

Loans made to customers

 

(2,709

)

(7,657

)

Payments on and proceeds from sales of loans receivable

 

1,007

 

7,220

 

Change in restricted cash

 

(70,941

)

4,297

 

Investments in other entities

 

(4,712

)

(1,024

)

Net cash used in investing activities

 

(117,224

)

(126,513

)

Cash flows from financing activities:

 

 

 

 

 

Proceeds from issuance of common stock and exercise of stock options

 

1,197

 

8,373

 

Proceeds from capital lease obligations and debt instruments

 

242,730

 

559

 

Contingent consideration paid relating to business acquisitions

 

(2,396

)

(350

)

Proceeds from revolving line of credit

 

34,383

 

31,701

 

Proceeds from minority interest DCE equity contribution

 

417

 

 

Proceeds from Chesapeake note

 

 

50,000

 

Payments for debt issuance costs

 

(3,053

)

 

Repayment of borrowing under revolving line of credit

 

(29,882

)

(27,819

)

Repayment of capital lease obligations and debt instruments

 

(15,854

)

(6,774

)

Net cash provided by financing activities

 

227,542

 

55,690

 

Effect of exchange rates on cash and cash equivalents

 

(512

)

686

 

Net increase (decrease) in cash

 

103,809

 

(89,057

)

Cash, beginning of period

 

55,194

 

238,125

 

Cash, end of period

 

$

159,003

 

$

149,068

 

Supplemental disclosure of cash flow information:

 

 

 

 

 

Income taxes paid

 

$

873

 

$

753

 

Interest paid, net of approximately $319 and $4,821 capitalized, respectively

 

2,551

 

9,224

 

 

See accompanying notes to condensed consolidated financial statements.

 

6



Table of Contents

 

Clean Energy Fuels Corp. and Subsidiaries

 

Notes to Condensed Consolidated Financial Statements

 

(Unaudited)

 

(In thousands, except share data)

 

Note 1—General

 

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

 

The Company has a broad customer base in a variety of markets, including trucking, airports, taxis, refuse, and public transit. The Company builds, operates, maintains or supplies approximately 323 natural gas fueling locations in 30 states within the United States, and in British Columbia and Ontario within Canada. The Company also generates revenue through operation and maintenance (“O&M”) agreements with certain customers, through building and selling or leasing natural gas fueling stations to its customers, and through manufacturing and servicing natural gas fueling compressors and related equipment, providing natural gas vehicle conversions, providing design and engineering services for natural gas engine systems, processing and selling renewable natural gas (“RNG”), and through financing its customers’ vehicle purchases.

 

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

 

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

 

Immaterial Revisions to Prior Years Financial Statements

 

During the third quarter of 2012, the Company identified certain immaterial errors in its previously issued financial statements as follows:

 

1)    Costs associated with fueling stations to be sold to third parties were previously reported on the balance sheets in construction in progress in land, property and equipment and as part of investing activities in the statements of cash flows.  The Company has changed the classification for these costs on the balance sheets from land, property and equipment to prepaid expenses and other current assets.  Additionally the Company has changed the reporting of advanced billings (deferred revenue on the balance sheet) for these projects to net such advanced billings against the costs of the related projects where costs exceed the billings. Advanced billings that exceed costs have been recorded as a net current liability within deferred revenue.  The statements of cash flows have been changed to reflect the costs for these projects as operating activities.

2)    Loans made to customers to finance vehicle purchases, net of repayments on the loans, were previously reported as cash flows from operating activities, and the proceeds from the subsequent sale of the loans have been reported as investing activities.  The Company considers its loans to customers to finance vehicle purchases as an investment activity and accordingly has changed the reporting of these loans and the repayments thereof from operating activities to investing activities within the statements of cash flows. Repayment amounts have been grouped with proceeds on loan sales as they are immaterial.

3)    The Company did not reflect certain non-cash investing activities (principally accrued purchases of property and equipment) in its statements of cash flows, which now have been adjusted.

 

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Table of Contents

 

The Company assessed the materiality of these errors for each quarterly and annual period and determined that the errors individually and in the aggregate were immaterial to previously reported amounts contained in its periodic reports. Accordingly, the Company has revised its consolidated balance sheets and statements of cash flows for all previously reported periods as noted below.  The Company intends to revise its consolidated financial statements for certain quarterly and annual periods through subsequent periodic filings. The particular financial statement captions have been revised as follows:

 

 

 

For the Year Ended
December 31, 2010

 

For the Year Ended
December 31, 2011

 

 

 

As Reported

 

As Revised

 

As Reported

 

As Revised

 

Cash flows from operating activities

 

(4,036

)

(10,703

)

(11,217

)

(27,136

)

 

 

 

 

 

 

 

 

 

 

Cash flows from investing activities

 

(68,734

)

(62,067

)

(181,826

)

(165,907

)

 

 

 

 

 

 

 

 

 

 

Prepaid expenses and other current assets

 

10,959

 

10,959

 

14,027

 

22,252

 

Land, property and equipment, net

 

211,643

 

203,174

 

277,334

 

257,463

 

Deferred revenue

 

17,507

 

9,038

 

21,267

 

9,621

 

 

 

 

For the Three Months
Ended March 31, 2011

 

For the Six Months Ended
June 30, 2011

 

For the Nine Months
Ended September 30, 2011

 

 

 

As Reported

 

As Revised

 

As Reported

 

As Revised

 

As Reported

 

As Revised

 

Cash flows from operating activities

 

9,897

 

10,867

 

9,886

 

10,644

 

1,978

 

(5,997

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash flows from investing activities

 

(40,577

)

(41,547

)

(57,698

)

(58,456

)

(125,199

)

(117,224

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Prepaid expenses and other current assets

 

11,970

 

12,645

 

12,889

 

14,528

 

12,345

 

21,641

 

Land, property and equipment, net

 

217,384

 

209,401

 

229,074

 

219,867

 

246,534

 

228,576

 

Deferred revenue

 

12,466

 

5,158

 

12,308

 

4,740

 

18,559

 

9,897

 

 

8



Table of Contents

 

 

 

For the Three Months
Ended March 31, 2012

 

For the Six Months Ended
June 30, 2012

 

 

 

As Reported

 

As Revised

 

As Reported

 

As Revised

 

Cash flows from operating activities

 

(15,079

)

(16,896

)

(6,251

)

(18,214

)

 

 

 

 

 

 

 

 

 

 

Cash flows from investing activities

 

(33,859

)

(32,042

)

(63,067

)

(51,104

)

 

 

 

 

 

 

 

 

 

 

Prepaid expenses and other current assets

 

13,966

 

28,931

 

15,132

 

37,243

 

Land, property and equipment, net

 

309,939

 

287,845

 

355,017

 

323,523

 

Deferred revenue

 

25,948

 

18,819

 

44,389

 

35,006

 

 

Totals as reported on previous consolidated balance sheets have been revised to reflect the above changes.

 

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

 

Note 2—Acquisitions

 

ServoTech

 

On February 25, 2011 (the “Closing Date”), the Company paid $1,200 for a 19.9% interest in ServoTech Engineering, Inc. (“ServoTech”), a company that provides, among other services, design and engineering services for natural gas fueling systems. In connection with the investment, the Company was granted an option to purchase the remaining 80.1% of ServoTech for $2,800 (the “Exercise Price”) during the 15 month period following the Closing Date (the “Purchase Option”). On April 30, 2012, the Company exercised the Purchase Option, paid 50% of the Exercise Price, or $1,400, in cash, on that date, and paid the remaining $1,400 of the Exercise Price in cash on October 31, 2012. Through March 31, 2012, the Company accounted for its interest in ServoTech using the equity method of accounting as the Company had the ability to exercise significant influence over ServoTech’s operations.

 

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

 

Current assets

 

$

2,655

 

Property & equipment

 

239

 

Identifiable intangible assets

 

3,913

 

Total assets acquired

 

6,807

 

Current liabilities assumed

 

(2,807

)

Total purchase price

 

$

4,000

 

 

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

 

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

 

Note 3—Cash and Cash Equivalents

 

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

 

Note 4— Restricted Cash

 

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

 

 

 

December 31,
2011

 

September 30,
2012

 

Short-term restricted cash

 

 

 

 

 

Standby letters of credit

 

$

1,237

 

$

1,226

 

DCEMB bonds — current operating costs

 

3,555

 

7,208

 

Total short-term restricted cash

 

4,792

 

8,434

 

Chesapeake loans

 

40,322

 

45,913

 

DCEMB bonds — long-term plant expansion

 

14,482

 

952

 

Total restricted cash

 

$

59,596

 

$

55,299

 

 

Note 5— Investments

 

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

 

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

 

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Short-term investments as of December 31, 2011 are summarized as follows:

 

 

 

Amortized
Cost

 

Gross
Unrealized
Losses

 

Estimated
Fair Value

 

Municipal bonds & notes

 

$

19,703

 

$

(114

)

$

19,589

 

Zero coupon bonds

 

712

 

 

712

 

Corporate bonds

 

3,040

 

(12

)

3,028

 

Total available-for-sale securities

 

23,455

 

(126

)

23,329

 

Certificate of deposits

 

10,000

 

 

10,000

 

Total short-term investments

 

$

33,455

 

$

(126

)

$

33,329

 

 

Short-term investments as of September 30, 2012 are summarized as follows:

 

 

 

Amortized
Cost

 

Gross
Unrealized
Losses

 

Estimated
Fair
Value

 

Municipal bonds & notes

 

$

17,272

 

(137

)

17,135

 

Corporate bonds

 

2,545

 

(41

)

2,504

 

Total available-for-sale securities

 

19,817

 

(178

)

19,639

 

Certificate of deposits

 

10,021

 

 

10,021

 

Total short-term investments

 

$

29,838

 

(178

)

29,660

 

 

As of September 30, 2012, all of the investments mature in one year or less.

 

Note 6—Derivative Transactions

 

The Company, in an effort to manage its natural gas commodity price risk exposures related to certain contracts, utilizes derivative financial instruments. From time to time, the Company enters into natural gas futures contracts that are over-the-counter swap transactions that convert its index-based gas supply arrangements to fixed price arrangements. As of September 30, 2012, all of the Company’s future contracts are being accounted for as cash flow hedges and are being used to mitigate the Company’s exposure to changes in the price of natural gas and not for speculative purposes.  The Company marks to market its open futures positions at the end of each period and records the net unrealized gain or loss during the period in derivative (gains) losses in the condensed consolidated statements of operations or in accumulated other comprehensive income in the condensed consolidated balance sheets in accordance with the Financial Accounting Standards Board’s (“FASB”) authoritative guidance. For the three month periods ended September 30, 2011 and 2012, the Company recorded unrealized gains of $476 and $157, respectively, in other comprehensive income (loss) related to its futures contracts. For the nine month periods ended September 30, 2011 and 2012, the Company recorded unrealized gains of $1,689 and $2,123, respectively, in other comprehensive income (loss) related to its futures contracts.  The Company’s net futures contracts liability of $135 at September 30, 2012 was recorded as an asset of $32 in prepaid expenses and other current assets and a liability of $167 in accrued liabilities, which are included in the Company’s condensed consolidated balance sheet. Of the $2,661 liability for the Company’s futures contracts at September 30, 2011, $2,546 is included in accrued liabilities for the short-term amount, and $115 is included in other long-term liabilities for the long-term amount in the Company’s condensed consolidated balance sheet. The Company’s ineffectiveness related to its futures contracts during the three and nine month periods ended September 30, 2011 and 2012 was insignificant. For the three months ended September 30, 2011 and 2012, the Company recognized a loss of approximately $864 and $100, respectively, in cost of sales in the accompanying condensed consolidated statements of operations related to its futures contracts that were settled during the respective periods. For the nine months ended September 30, 2011 and 2012, the Company recognized a loss of $2,295 and $2,403, respectively, in cost of sales in the accompanying condensed consolidated statements of operations related to its futures contracts that were settled during the respective periods. These amounts were reclassified from accumulated other comprehensive income (loss).  As of September 30, 2012, the remaining unrecognized loss of $135 is recorded as a component of accumulated other comprehensive income (loss).  The Company expects to reclassify such unrecognized loss from accumulated other comprehensive income (loss) as cost of sales through June 30, 2013.

 

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

 

 

 

Gallons

 

Weighted
Average Price
Per Gasoline
Gallon
Equivalent

 

October to December, 2012

 

600,000

 

$

0.54

 

January to June, 2013

 

1,140,000

 

$

0.53

 

 

Note 7—Other Receivables

 

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

 

 

 

December 31,
2011

 

September 30,
2012

 

Loans to customers to finance vehicle purchases

 

$

1,789

 

$

4,270

 

Capital lease receivables

 

310

 

304

 

Accrued customer billings

 

5,860

 

9,843

 

Fuel tax and carbon credits

 

5,912

 

5,470

 

Other

 

5,730

 

4,284

 

 

 

$

19,601

 

$

24,171

 

 

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 September 30, 2012:

 

 

 

December 31,
2011

 

September 30,
2012

 

Raw materials and spare parts

 

$

30,177

 

$

32,177

 

Work in process

 

2,310

 

3,902

 

Finished goods

 

2,800

 

1,264

 

Total

 

$

35,287

 

$

37,343

 

 

Note 9—Land, Property and Equipment

 

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

 

 

 

December 31,
2011

 

September 30,
2012

 

Land

 

$

1,198

 

$

1,198

 

LNG liquefaction plants

 

93,109

 

93,357

 

RNG plants

 

21,005

 

23,575

 

Station equipment

 

118,613

 

141,091

 

LNG trailers

 

13,532

 

13,564

 

Other equipment

 

26,508

 

42,930

 

Construction in progress

 

66,256

 

161,692

 

 

 

340,221

 

477,407

 

Less: accumulated depreciation

 

(82,758

)

(101,395

)

 

 

$

257,463

 

$

376,012

 

 

Note 10—Investments in Other Entities

 

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

 

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The Company has invested in Clean Energy del Peru (“Peru JV”), a joint venture in Lima, Peru that operates CNG stations. The Company accounts for its investment in Peru JV under the equity method of accounting as the Company has the ability to exercise significant influence over Peru JV’s operations.  At September 30, 2012, this investment had a balance of $2,562.

 

Note 11— Accrued Liabilities

 

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

 

 

 

December 31,
2011

 

September 30,
2012

 

Salaries and wages

 

$

5,088

 

$

9,042

 

Accrued gas purchases

 

4,773

 

8,949

 

Derivative liabilities

 

2,259

 

477

 

Contingent consideration obligation

 

378

 

412

 

Accrued property and other taxes

 

3,043

 

2,569

 

Accrued professional fees

 

875

 

767

 

Accrued employee benefits

 

1,431

 

3,338

 

Accrued warranty liability

 

3,130

 

2,587

 

Other

 

7,278

 

2,424

 

 

 

$

28,255

 

$

30,565

 

 

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:

 

 

 

September 30,
2011

 

September 30,
2012

 

Warranty liability at beginning of year

 

$

2,338

 

$

3,130

 

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

 

1,977

 

2,836

 

Service obligations honored

 

(1,544

)

(3,379

)

Warranty liability at end of period

 

$

2,771

 

$

2,587

 

 

Note 13—Long-term Debt

 

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

 

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

 

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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 condensed 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 (the “Shell Gas Sale Agreement”) with Shell Energy North America (US), L.P. (“Shell Energy”), and the funds and accounts held under the Indenture.

 

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

 

All payments received by the Depository Bank will be placed into various accounts in accordance with the requirements of the Indenture and the Depository Agreement. The funds in these accounts will be used to service required debt payments, finance further improvements and expansion of the landfill gas processing facility owned by DCEMB, finance the operations and maintenance of DCEMB, finance certain expenses associated with setting up and maintaining the accounts, and other uses as prescribed in the Depository Agreement. The Depository Bank will make payments out of these accounts in accordance with the requirements of the Depository Agreement. At the end of each month after all required account fundings have been fulfilled in accordance with the Depository Agreement, all remaining excess funds will be placed into a surplus account. The funds in the surplus account will be delivered to DCEMB so long as (i) DCEMB’s Debt Service Coverage Ratio (as defined) for the most recent four calendar quarters then ended equals or exceeds 1.25:1, (ii) DCEMB’s Debt Service Coverage Ratio (as defined) is reasonably projected to equal or exceed 1.25:1 for the next four calendar quarters, (iii) no events of default have occurred as defined by the Indenture and the Loan Agreement, and (iv) after giving effect to the transfer, DCEMB’s Minimum Days Cash on Hand (as defined) shall be, or shall at any time be projected to be, more than the lesser of thirty-five Days Cash on Hand (as defined) or $1,300. Due to these restrictions on this cash, the Company has classified all of this cash as restricted cash on the balance sheet. The Company records the restricted cash that is expected to be received and used within the next 12 months from the Depository Bank for working capital and operating purposes as current in its balance sheet, and presents the remaining balance as non-current. At September 30, 2012, $7,208 was recorded as short-term restricted cash and $952 was recorded as long-term restricted cash in the accompanying condensed consolidated balance sheet.

 

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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 September 30, 2012, DCEMB was in compliance with all its debt covenants.

 

Purchase Notes

 

In connection with the closing of the Company’s acquisition of IMW in September 2010, the Company agreed to make future payments consisting of four annual payments in the amount of $12,500 (collectively the “IMW Notes”). Each payment under the IMW Notes will consist of $5,000 in cash and $7,500 in cash and/or shares of the Company’s common stock (the exact combination of cash and/or stock to be determined at the Company’s option). In addition, pursuant to a security agreement executed at closing, the IMW Notes are secured by a subordinate security interest in IMW. In January 2011, the Company paid $5,000 in cash and $7,500 in shares of its common stock.  The Company paid $5,000 in cash in January 2012 and $3,750 in shares of its common stock in each of August 2012 and October 2012.

 

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

 

In connection with the closing of the Company’s acquisition of the natural gas vehicle fueling infrastructure construction business of Weaver Electric, Inc. in October 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 in October 2012.  In May 2012, the Company prepaid $125 of the October 2012 payment, and the remaining amount of such payment was paid in October 2012.

 

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

 

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

 

IMW Lines of Credit

 

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

 

(i)                                     An operating line of credit with a limit of $10,000 in Canadian dollars (“CAD”) to assist in financing the day-to-day working capital needs of IMW. The interest on amounts outstanding shall be payable at IMW’s option at (a) HSBC’s Prime Rate plus 1.00% per annum, (b) HSBC’s U.S. Base Rate plus 1.00% per annum, or LIBOR plus 2.25% per annum, subject to availability.  On July 4, 2012, IMW and HSBC amended the IMW Lines of Credit and increased the limit of the operating line of credit to CAD$13,000 from CAD$10,000.

 

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

 

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

 

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

 

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

 

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(vii)                           An operating line of credit with a limit of 5,000 Renminbi (“RMB”) (CAD$776) bearing interest at the 6 month People’s Bank of China rate plus 2.5% and a sub-limit bank guarantee line of 5,000 RMB. The aggregate of the balances in the lines cannot exceed 5,000 RMB.

 

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

 

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

 

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

 

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

 

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

 

Chesapeake Notes

 

On July 11, 2011, the Company entered into a Loan Agreement (the “CHK Agreement”) with Chesapeake NG Ventures Corporation (“Chesapeake”), an indirect wholly owned subsidiary of Chesapeake Energy Corporation, whereby Chesapeake agreed to purchase from the Company up to $150,000 of debt securities for the development, construction and operation of liquefied natural gas stations (the “CHK Financing”) pursuant to the issuance of three convertible promissory notes, each having a principal amount of $50,000 (each a “CHK Note” and collectively the “CHK Notes”). Chesapeake Energy Corporation guaranteed Chesapeake’s commitment to purchase the CHK Notes under the CHK Agreement.

 

The first CHK Note was issued on July 11, 2011, the second CHK Note was issued on July 10, 2012, and the Company expects to issue the third Note on or about June 28, 2013.  The CHK Notes bear interest at the rate of 7.5% per annum (payable quarterly, in arrears, on March 31, June 30, September 30 and December 31 of each year) and are convertible at Chesapeake’s option into shares of the Company’s common stock at a conversion price of $15.80 per share (the “CHK Conversion Price”). Subject to certain restrictions, the Company can force conversion of each CHK Note into shares of the Company’s common stock if, following the second anniversary of the issuance of a CHK Note, the Company’s shares of common stock trade at a 40% premium to the CHK Conversion Price for at least 20 trading days in any consecutive 30 trading day period. The entire principal balance of each CHK Note is due and payable seven years following its issuance, and the Company may repay each CHK Note in shares of the Company’s common stock or cash. The CHK Agreement restricts the use of the CHK Financing proceeds to financing the development, construction and operation of liquefied natural gas stations and payment of certain related expenses. At September 30, 2012, $45,913 of these funds were included in long term restricted cash. 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

 

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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 September 30, 2012, the Company met its obligations under the CHK Registration Rights Agreement.

 

SLG Notes

 

On August 24, 2011, the Company entered into Convertible Note Purchase Agreements (each, an “SLG Agreement” and collectively the “SLG Agreements”) with each of Springleaf Investments Pte. Ltd., a wholly-owned subsidiary of Temasek Holdings Pte. Ltd., Lionfish Investments Pte. Ltd., an investment vehicle managed by Seatown Holdings International Pte. Ltd., and Greenwich Asset Holding Ltd., a wholly-owned subsidiary of RRJ Capital Master Fund I, L.P. (each, a “Purchaser” and collectively, the “Purchasers”), whereby the Purchasers agreed to purchase from the Company $150,000 of 7.5% convertible notes due in August 2016 (each a “SLG Note” and collectively the “SLG Notes”). The transaction closed and the SLG Notes were issued on August 30, 2011. On March 1, 2012, Springleaf Investments Pte. LTD transferred $24,000 principal amount of the SLG Notes to Baytree Investments (Mauritius) Pte Ltd.

 

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

 

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 September 30, 2012, the Company met its obligations under the SLG Registration Rights Agreement.

 

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

 

 

 

December 31,
2011

 

September 30,
2012

 

IMW Notes

 

$

34,400

 

$

27,398

 

Northstar future payments

 

2,388

 

2,510

 

ServoTech future payment

 

 

1,400

 

DCE Notes

 

585

 

585

 

DCEMB Revenue Bonds (non recourse to the Company)

 

39,400

 

39,400

 

Chesapeake Notes

 

50,000

 

100,000

 

SLG Notes

 

150,000

 

149,000

 

Weaver Electric future payments

 

872

 

793

 

IMW debt

 

6,657

 

12,928

 

Capital lease obligations

 

5,120

 

3,980

 

Total debt and capital lease obligations

 

289,422

 

337,994

 

Less amounts due within one year and short-term borrowings

 

(22,925

)

(34,068

)

Total long-term debt and capital lease obligations

 

$

266,497

 

$

303,926

 

 

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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
September 30,

 

Nine Months Ended
September 30,

 

 

 

2011

 

2012

 

2011

 

2012

 

Basic and diluted:

 

 

 

 

 

 

 

 

 

Weighted average number of common shares outstanding

 

70,364,202

 

87,006,024

 

70,255,311

 

86,441,196

 

 

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

 

 

 

September 30,

 

 

 

2011

 

2012

 

Options

 

10,753,026

 

10,468,648

 

Warrants

 

17,130,682

 

2,130,682

 

Convertible notes

 

13,164,557

 

16,262,226

 

Restricted stock units

 

 

1,545,000

 

 

Note 15—Stock-Based Compensation

 

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

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2011

 

2012

 

2011

 

2012

 

 

 

 

 

 

 

 

 

 

 

Stock-based compensation expense

 

$

3,161

 

$

6,044

 

$

10,093

 

$

16,492

 

Stock-based compensation expense, net of tax

 

$

3,161

 

$

6,044

 

$

10,093

 

$

16,492

 

 

Stock Options

 

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

 

 

 

Number of
Shares

 

Weighted
Average
Exercise
Price

 

Weighted
Average
Remaining
Contractual
Term (in years)

 

Aggregate
Intrinsic
Value

 

Outstanding, December 31, 2011

 

10,683,303

 

$

10.29

 

 

 

 

 

Options granted

 

1,374,500

 

14.93

 

 

 

 

 

Options exercised

 

(1,451,050

)

5.77

 

 

 

 

 

Options forfeited

 

(138,105

)

14.06

 

 

 

 

 

Outstanding, September 30, 2012

 

10,468,648

 

$

11.47

 

6.09

 

$

17,796

 

Exercisable, September 30, 2012

 

7,400,366

 

$

10.28

 

5.36

 

$

21,387

 

 

As of September 30, 2012, there was $16,935 of total unrecognized compensation cost related to non-vested shares. That cost is expected to be recognized over a weighted average period of 1.3 years. The total fair value of shares vested during the nine months ended September 30, 2012 was $4,875.

 

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 nine months ended September 30, 2011 and 2012 was $1,337 and $17,971, respectively.

 

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

 

 

 

Nine Months Ended
September 30, 2012

 

Dividend yield

 

0.00%

 

Expected volatility

 

58.5% to 72.8%

 

Risk-free interest rate

 

0.9% to 1.2%

 

Expected life in years

 

6.0

 

 

The weighted-average grant date fair values of options granted during the nine months ended September 30, 2011 and 2012 were $9.03, and $8.94, respectively. The volatility amounts used during the period were estimated based on a certain peer group of the Company’s historical volatility for a period commensurate with the expected life of the options granted, the Company’s historical volatility, and the Company’s implied volatility of its traded options. The expected lives used during the periods were based on historical exercise periods and the Company’s anticipated exercise periods for its outstanding options. The risk free rates used during the year were based on the U.S. Treasury yield curve for the expected life of the options at the time of grant. The Company recorded $10,093 and $10,809 of stock option expense during the nine months ended September 30, 2011 and 2012, respectively. The Company has not recorded any tax benefit related to its stock option expense.

 

Restricted Stock Units

 

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

 

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

 

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

 

 

 

Number of
Shares

 

Weighted Average
Fair Value at
Grant Date

 

Weighted
Average
Remaining
Contractual
Term (in years)

 

Outstanding, December 31, 2011

 

 

 

 

 

Granted

 

1,545,000

 

$

11.42

 

 

 

Outstanding and non-vested, September 30, 2012

 

1,545,000

 

$

11.42

 

3.5

 

 

As of September 30, 2012, there was $11,959 of total unrecognized compensation cost related to non-vested units. That cost is expected to be recognized over a weighted average period of 1.1 years.

 

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

 

 

 

January 25,
2012

 

May 8, 2012

 

Stock price on date of grant

 

$

15.11

 

$

16.71

 

Dividend yield

 

0.00

%

0.00

%

Expected volatility

 

56.51

%

58.49

%

Risk-free interest rate

 

0.57

%

0.56

%

Expected life in years

 

2.1

 

2.0

 

 

The volatility amounts used during the period were estimated based on the Company’s historical volatility for a period commensurate with the term of the RSUs granted and the Company’s implied volatility of its traded options. The expected life of the RSUs was derived using the Monte Carlo Method. The risk free rates used during the year were based on the U.S. Treasury yield curve for the expected term of the RSUs at the date of grant. The Company recorded $5,683 of expense and has not recorded any tax benefit related to the expense of the RSUs during the nine months ended September 30, 2012.

 

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

 

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

 

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

 

The Company is required to obtain certifications from the California Air Resources Board (“CARB”) on the engine kits used in its vehicle conversions that are sold in California.  The Company has determined that certain vehicles sold in California may have been shipped prior to obtaining final CARB approval, and as a result, there is a possibility of penalties being assessed by CARB.  The vehicles in question ultimately did receive their certifications.  As of September 30, 2012, the Company is in the process of evaluating the facts and circumstances of this possible assessment and is in discussions with CARB.  The Company believes that an assessment is reasonably possible and cannot estimate a range of possible losses beyond the maximum range of losses of $0 to $2,000.

 

Note 17—Income Taxes

 

The effective tax rate for the three months and nine months ended September 30, 2011 and 2012 is different from the federal statutory tax rate primarily as a result of losses for which no tax benefit has been recognized.  The Company is required to recognize the impact of a tax position in its financial statements if the position meets the more likely than not threshold of being sustained by the taxing authority upon examination, based on the technical merits of the position. The Company accrues interest based on the difference between a tax position recognized in the financial statements and the amount claimed on its returns at statutory interest rates. The net interest incurred was immaterial for the nine months ended September 30, 2011 and 2012. Further, the Company accrues penalties if the tax position does not meet the minimum statutory threshold to avoid penalties. No penalties have been accrued by the Company. The Company’s unrecognized tax benefits as of September 30, 2012 were unchanged from December 31, 2011.

 

The Company is subject to taxation in the United States and various state and foreign jurisdictions. The Company’s taxes for 2008 through 2011 are subject to examination by various tax authorities. The Company is no longer subject to United States examination for years before 2009, and state examinations for years before 2008.  On July 15, 2010, the IRS sent the Company a letter disallowing approximately $5,073 related to certain claims the Company made from October 1, 2006 to June 30, 2008 under the VETC program and is seeking repayment of such amount. The Company believes its claims were properly made and has appealed the IRS’s request for payment.  As of September 30, 2012, the Company has entered into negotiations with certain parties involved in the claims, but the negotiations are ongoing and no binding contractual agreements have been reached.  The Company cannot reasonably estimate a range of probable losses associated with these claims beyond the maximum possible range of losses of $0 to $5,073.

 

Note 18—Fair Value Measurements

 

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

 

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Table of Contents

 

Observable inputs are inputs market participants would use in valuing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions about the factors market participants would use in valuing the asset or liability developed based upon the best information available in the circumstances. The hierarchy consists of the following three levels: Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities; Level 2 inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and inputs (other than quoted prices) that are observable for the asset or liability, either directly or indirectly; Level 3 inputs are unobservable inputs for the asset or liability. Categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement.

 

During the nine months ended September 30, 2012, the Company’s financial instruments consisted of available-for-sale securities, natural gas futures contracts, debt instruments, a contingent consideration obligation, and its Series I warrants. For securities available-for-sale, the fair value is determined by the most recent trading prices available for each security or for comparable securities, and thus represent Level 2 fair value measurements. The Company uses quoted forward price curves, discounted to reflect the time value of money, to value its natural gas futures contracts which is considered to be a Level 2 fair value measurement. The Company uses an income approach, projecting the financial results for the associated entity, discounted to reflect the time value of money, to value its contingent consideration obligation, which is considered to be a Level 3 fair value measurement. The fair market value of the Company’s debt instruments approximated their carrying values at September 30, 2011 and 2012. The Company uses the Black-Scholes model to value the Series I warrants. The Company believes the best method to approximate the market participant’s view of the volatility of its Series I warrants is to use the implied volatilities of its short-term (i.e. 3 to 9 month) traded options and extrapolate the data over the remaining term of the Series I warrants, which was approximately 3.58 years as of September 30, 2012. This method has been utilized consistently in the periods presented. Given that the extrapolation beyond the term of the short term exchange traded options is not based on observable market inputs for a significant portion of the remaining term of the warrants, the Series I warrants have been classified as a Level 3 fair value determination in the table below.

 

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 September 30, 2012, respectively:

 

Description

 

Balance at
December 31,
2011

 

Level 1

 

Level 2

 

Level 3

 

Assets:

 

 

 

 

 

 

 

 

 

Available-for-sale securities (1):

 

 

 

 

 

 

 

 

 

Certificate of deposits

 

$

10,000

 

$

 

$

10,000

 

$

 

Municipal bonds and notes

 

19,589

 

 

19,589

 

 

Zero coupon bonds

 

712

 

 

712

 

 

Corporate bonds

 

3,028

 

 

3,028

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

Natural gas futures contracts (2)

 

2,335

 

 

2,335

 

 

Contingent consideration obligation (3)

 

5,978

 

 

 

5,978

 

Series I warrants (4)

 

11,493

 

 

 

11,493

 

 

Description

 

Balance at
September 30,
2012

 

Level 1

 

Level 2

 

Level 3

 

Assets:

 

 

 

 

 

 

 

 

 

Available-for-sale securities (1):

 

 

 

 

 

 

 

 

 

Certificate of deposits

 

$

10,021

 

$

 

$

10,021

 

$

 

Municipal bonds and notes

 

17,135

 

 

17,135

 

 

Corporate bonds

 

2,504

 

 

2,504

 

 

Natural gas futures contracts (2)

 

32

 

 

 

32

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

Natural gas futures contracts (2)

 

167

 

 

167

 

 

Contingent consideration obligation (3)

 

1,634

 

 

 

1,634

 

Series I warrants (4)

 

10,408

 

 

 

10,408

 

 


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

(2) See note 6 for further information.

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

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

 

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Table of Contents

 

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

 

Liabilities: Contingent Consideration

 

September 30,
2011

 

September 30,
2012

 

Balance beginning of year

 

$

11,200

 

$

5,978

 

Total gain included in earnings (1)

 

(2,554

)

(3,994

)

Payments

 

(2,396

)

(350

)

Ending Balance

 

$

6,250

 

$

1,634

 

 

Liabilities: Series I Warrants

 

September 30,
2011

 

September 30,
2012

 

Balance beginning of year

 

$

14,148

 

$

11,493

 

Total gain included in earnings

 

(3,059

)

(1,085

)

Ending Balance

 

$

11,089

 

$

10,408

 

 


(1) Included in selling, general and administrative expense in the condensed consolidated statements of operations.

 

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

 

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

 

Contingent Consideration

 

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

 

Unobservable Input

 

Range or Weighted Average

 

Gross profit projection

 

$9,060 - $32,641

 

Probability of reaching target gross profit

 

0.0% - 70.0%

 

Volatility of gross profit (peer group)

 

13.4% - 56.9% (simple average 31.6%)

 

Risk adjusted discount rate

 

46.3%

 

 

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

 

Series I Warrant Liability

 

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

 

Unobservable Input

 

Range or Weighted Average

 

Current market price of the Company’s common stock

 

$13.17

 

Exercise price of the warrant

 

$12.68

 

Remaining term of the warrant

 

3.58

 

Implied volatility of the Company’s common stock

 

50.7% - 51.8%

 

Assumed discount rate

 

Simple average 0.3%

 

 

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Table of Contents

 

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

 

Non-financial assets

 

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

 

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

 

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

 

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

 

The Company records its VETC credits as revenue in its condensed consolidated statements of operations as the credits are fully refundable and do not need to offset income tax liabilities to be received. VETC revenues for the three and nine month periods ended September 30, 2011 were $4,539 and $13,441, respectively. No VETC revenues were recognized in 2012 as the 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 Securities and Exchange Commission on March 12, 2012, as well as the consolidated financial statements and notes contained therein.  Unless the context indicates otherwise, all references to “Clean Energy,” the “Company,” “we,” “us,” or “our” in this MD&A and elsewhere in this report refer to Clean Energy Fuels Corp. together with its majority and wholly owned subsidiaries.

 

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Cautionary Statement Regarding Forward Looking Statements

 

This MD&A and other sections of this report contain forward looking statements. We make forward-looking statements, as defined by the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, and in some cases, you can identify these statements by forward-looking words such as “if,” “shall,” “may,” “might,” “will likely result,” “should,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “project,” “intend,” “goal,” “objective,” “predict,” “potential” or “continue,” or the negative of these terms and other comparable terminology. These forward-looking statements, which are based on various underlying assumptions and expectations and are subject to risks, uncertainties and other unknown factors, may include projections of our future financial performance based on our growth strategies and anticipated trends in our business. These statements are only predictions based on our current expectations and projections about future events that we believe to be reasonable. There are important factors that could cause our actual results, level of activity, performance or achievements to differ materially from the historical or future results, level of activity, performance or achievements expressed or implied by such forward-looking statements. These factors include, but are not limited to, those discussed under the caption “Risk Factors” in this report and in our 2011 Annual Report on Form 10-K. In preparing this MD&A, we presume that readers have access to and have read the MD&A in our 2011 Annual Report on Form 10-K pursuant to Instruction 2 to paragraph (b) of Item 303 of Regulation S-K. We undertake no duty to update any of these forward-looking statements after the date of filing of this report to conform such forward-looking statements to actual results or revised expectations, except as otherwise required by law.

 

We provide natural gas solutions for vehicle fleets primarily in the U.S. and Canada. Our primary business activity is selling compressed natural gas (“CNG”) and liquefied natural gas (“LNG”) vehicle fuel to our customers. We also manufacture and service advanced natural gas fueling compressors and related equipment, build, operate and maintain fueling stations, sell or lease fueling stations to our customers, process and sell renewable natural gas (“RNG”), provide natural gas vehicle conversions, and provide design and engineering services for natural gas engine systems. 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. On April 30, 2012, we exercised the Purchase Option to purchase the remaining 80.1% interest in ServoTech Engineering, Inc. (“ServoTech”), a company that provides, among other services, design and engineering services for natural gas engine systems.

 

Overview

 

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

 

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

 

Key operating data.   In evaluating our operating performance, our management focuses primarily on: (1) the amount of CNG and LNG gasoline gallon equivalents delivered (which we define as (i) the volume of gasoline gallon equivalents we sell to our customers, plus (ii) the volume of gasoline gallon equivalents dispensed to our customers at stations where we provide operating and maintenance (“O&M”) services, but do not sell the CNG or LNG, plus (iii) our proportionate share of the gasoline gallon equivalents sold as CNG by our joint venture in Peru, plus (iv) our proportionate share of the gasoline gallon equivalents of RNG produced and sold as pipeline quality natural gas by DCE), (2) our gross margin (which we define as revenue minus cost of sales), and (3) net income (loss) attributable to us. The following table, which you should read in conjunction with our condensed consolidated financial statements and notes contained elsewhere in this quarterly report on Form 10-Q and our consolidated financial statements and notes contained in our 2011 Annual Report on Form 10-K for the year ended December 31, 2011, presents our key operating data for the years ended December 31, 2009, 2010, and 2011 and for the three and nine months ended September 30, 2011 and 2012:

 

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Gasoline gallon
equivalents
delivered (in millions)

 

Year Ended
December 31,
2009

 

Year Ended
December 31,
2010

 

Year Ended
December 31,
2011

 

Three Months
Ended
September 30,
2011

 

Three Months
Ended
September 30,
2012

 

Nine Months
Ended
September 30,
2011

 

Nine Months
Ended
September 30,
2012

 

CNG

 

67.9

 

81.4

 

101.8

 

26.8

 

34.1

 

75.1

 

95.3

 

RNG

 

6.4

 

7.4

 

6.7

 

1.8

 

2.3

 

5.0

 

6.4

 

LNG

 

26.7

 

33.9

 

47.1

 

12.3

 

14.5

 

35.5

 

41.5

 

Total

 

101.0

 

122.7

 

155.6

 

40.9

 

50.9

 

115.6

 

143.2

 

Operating data (in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross margin

 

$

48,582

 

$

69,945

 

$

76,033

 

$

19,328

 

$

20,228

 

$

56,354

 

$

59,288

 

Net loss attributable to Clean Energy Fuels Corp.

 

(33,249

)

(2,516

)

(47,633

)

(11,354

)

(16,321

)

(26,726

)

(59,520

)

 

Key trends in 2009, 2010, 2011 and the first nine 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 323 at September 30, 2012 (a 64.8% increase). Included in this number are all of the CNG and LNG fueling stations we own, maintain or with which we have a fueling supply contract. The amount of CNG, RNG and LNG gasoline gallon equivalents we delivered from 2009 to 2011 increased by 54%. The increase in gasoline gallon equivalents delivered was the primary contributor to increased revenues during 2009, 2010 and 2011. In addition, in 2011, we also benefitted from increased revenues from compressor sales and fueling station installations as a result of our acquisitions of IMW and Northstar, which occurred during the fourth quarter of 2010.

 

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

 

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

 

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

 

During 2011 and the first nine months of 2012, prices for oil, gasoline, and diesel fuel were generally substantially higher than the price for natural gas. Oil hit a high of $107.07 in February 2012 and settled at $92.19 per barrel on September 30, 2012. In California, average retail prices for gasoline have increased from $3.68 per gallon in January 2012 to $4.20 per gallon at September 30, 2012, and the average retail price for diesel fuel hit a high of $4.49 per diesel gallon in September 2012 and settled at $4.39 per diesel gallon at September 30, 2012. Higher gasoline and diesel prices typically improve our margins on fuel sales to the extent we price fuel at a discount to gasoline or diesel. During this time period, the NYMEX price for natural gas fluctuated from a high of $3.08 per MMbtu in January 2012 to $2.63 per MMbtu at September 30, 2012. The average retail sales price of our CNG fuel sold in the Los Angeles metropolitan area ranged from $2.60 for the month of January 2011 to $2.90 for the month of September 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 $3.00 at September 30, 2012.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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Many governmental entities, which represented approximately 36% of our revenues from January 1, 2011 through September 30, 2012, are experiencing significant budget deficits as a result of the economic recession and have been, and may continue to be, unable to invest in new natural gas vehicles for their transit or refuse fleets. They may also be compelled to reduce public transportation and services, or the prices they pay for these services, which would negatively affect our business.

 

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

 

Our business plan calls for approximately $45.8 million in capital expenditures from October 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, and to make capital expenditures to build additional LNG production facilities or to otherwise secure future LNG supply. We will need to raise additional capital as necessary to fund any capital expenditures or investments that we cannot fund through available cash or cash generated by operations. The timing and necessity of any future capital raise will depend on our rate of new station construction and potential merger or acquisition activity. For more information, see “Liquidity and Capital Resources” and “Capital Expenditures” below. We may not be able to raise capital on terms that are favorable to existing stockholders or at all. Any inability to raise capital may impair our ability to invest in new stations, develop natural gas fueling infrastructure and invest in strategic transactions or acquisitions, and may reduce our ability to grow our business and generate increased revenues.

 

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

 

Operations

 

We generate revenues principally by selling CNG and LNG and providing O&M services to our vehicle fleet customers. For the nine months ended September 30, 2012, CNG and RNG (together) represented 71% and LNG represented 29% of our natural gas sales (on a gasoline gallon equivalent basis). To a lesser extent, we generate revenues by designing and constructing fueling stations and selling or leasing those stations to our customers. We also generate material revenues through sales of RNG produced by our joint venture subsidiary DCE, sales of natural gas vehicles by our wholly owned subsidiary BAF, sales of advanced natural gas fueling compressors and related equipment and maintenance services through IMW, and sales of LNG and LCNG fueling station design, construction and O&M services through Northstar. Substantially all of our operating and maintenance revenues are generated from CNG stations, as owners of LNG stations typically operate and maintain their own stations. Substantially all of our station sales and leasing revenues have been generated from CNG stations.

 

CNG Sales

 

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

 

LNG Sales

 

We sell LNG to fleet customers, who typically own and operate their fueling stations. Increasingly, we also sell LNG to fleet and other customers at our public-access LNG stations. During 2012, we procured 41% 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.

 

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America’s Natural Gas Highway

 

We are building 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 and July 2012 financing transactions with Chesapeake to help fund the cost of building the stations. We expect to generate revenue through sales of natural gas fuel to operators of heavy duty trucks and other vehicles at these planned fueling stations.

 

Government Incentives

 

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

 

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

 

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 nine months ended September 30, 2011 and 2012, Northstar contributed approximately $7.6 million and $3.5 million, respectively, to our revenue, reflecting a migration of Northstar’s operations toward the build out of LNG stations for ANGH.

 

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 lend 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 September 30, 2012, we have not generated significant revenue from vehicle financing activities.

 

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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 nine months ended September 30, 2011 and 2012, DCE generated approximately $9.0 million and $11.3 million, respectively, in revenue from sales of RNG, all of which is included in our condensed consolidated statements of operations.

 

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

 

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

 

The sale price for the gas under the Shell Gas Sale Agreement is fixed, and represents a substantial premium to the current prevailing prices for natural gas at November 9, 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 during the fourth quarter of 2012. Canton Renewables has executed an agreement with an affiliate of the local gas utility that will enable Canton Renewables to inject the RNG produced into the local gas transmission system and transport it to the interstate pipeline, where it may be distributed for use in power generation or as a low-carbon, renewable vehicle fuel. We have entered into a ten-year fixed-price sale contract for the majority of the RNG we expect this landfill gas facility to produce; provided that such sale contract may be terminated by either party with prior written notice if a governmental authority makes a final determination or adopts a law, ruling or regulation that would result in the RNG subject to the agreement no longer being able, when combusted, to generate RPS eligible renewable energy.

 

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

 

Vehicle Conversions and Engineering Services

 

On October 1, 2009, we completed our acquisition of BAF. Founded in 1992, BAF provides natural gas vehicle (“NGV”) conversions, alternative fuel systems, application engineering, service and warranty support and research and development. BAF’s vehicle conversions include taxis, vans, pick-up trucks and shuttle buses. BAF utilizes advanced natural gas system integration technology and has certified NGVs under both EPA and CARB standards achieving Super Ultra Low Emission Vehicle emissions. On April 30, 2012, we exercised the Purchase Option to purchase the remaining 80.1% interest in ServoTech.  ServoTech provides, among other services, design and engineering services for natural gas fueling systems. We generate revenues through the sale of natural gas vehicles that have been converted to run on natural gas by BAF, and design and engineering services for natural gas fueling systems by ServoTech. The majority of BAF’s revenue during 2010 and 2011 was derived from sales of converted natural gas service vans to AT&T. During the first nine months of 2011 and 2012, BAF and ServoTech, combined, contributed approximately $18.8 million and $18.3 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 nine months ended September 30, 2011 and 2012, IMW contributed approximately $46.5 million and $43.1 million, respectively, to our revenue.

 

Volatility of Earnings and Cash Flows

 

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

 

Additionally, we are required to maintain a margin account to cover losses related to our natural gas futures contracts. Futures contracts are valued daily, and if our contracts are in loss positions at the end of a trading day, our broker will transfer the amount of the losses from our margin account to a clearinghouse. If at any time the funds in our margin account drop below a specified maintenance level, our broker will issue a margin call that requires us to restore the balance. Consequently, these payments could significantly impact our cash balances. At September 30, 2012, we had paid $0.6 million in margin deposits, which are included in prepaid expenses and other current 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 gain of $3.1 million and $1.1 million related to recording the estimated fair value changes of our Series I warrants in the nine months ended September 30, 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.  As of September 30, 2012, 2,130,682 of the Series I warrants remained outstanding.

 

Volatility of Earnings Related to Contingent Consideration

 

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

 

If the anticipated results of IMW increase or decrease during future periods, we may be required to recognize material losses or gains based on the valuation of the increased or decreased consideration due to the former IMW shareholder. During the first nine months of 2012, we recognized a gain of $4.0 million related to the estimated change in the value of the IMW contingent consideration. Our earnings or loss per share may be materially affected by future gains or losses we are required to recognize as a result of changes in the estimated fair value of the contingent consideration amount.

 

Debt Compliance

 

In connection with our acquisition of IMW, we entered into a credit agreement with HSBC that requires IMW to comply with certain financial covenants (see note 13 to our condensed consolidated financial statements). If we were to violate a covenant, we would seek a waiver from the bank, which the bank is not obligated to grant. If the bank does not grant a waiver, all of the obligations under the credit agreement would be due and payable. IMW was in compliance with these covenants as of September 30, 2012.

 

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

 

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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 September 30, 2012, we were in compliance with these debt covenants.

 

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

 

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

 

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

 

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

 

Risk Management Activities

 

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

 

Critical Accounting Policies

 

For the nine months ended September 30, 2012, there were no material changes to the “Critical Accounting Policies” discussed in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) of our 2011 Annual Report on Form 10-K.

 

Recently Issued Accounting Pronouncements

 

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

 

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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
September 30,

 

Nine Months
Ended
September 30,

 

 

 

2011

 

2012

 

2011

 

2012

 

Statement of Operations Data:

 

 

 

 

 

 

 

 

 

Revenue:

 

 

 

 

 

 

 

 

 

Product revenues

 

89.1

%

90.4

%

89.2

%

87.8

%

Service revenues

 

10.9

 

9.6

 

10.8

 

12.2

 

Total revenue

 

100.0

 

100.0

 

100.0

 

100.0

 

Operating expenses:

 

 

 

 

 

 

 

 

 

Cost of sales:

 

 

 

 

 

 

 

 

 

Product cost of sales

 

67.8

 

73.7

 

67.6

 

69.4

 

Service cost of sales

 

5.4

 

4.2

 

5.1

 

5.4

 

Derivative gains on Series I warrant valuation

 

(2.1

)

(6.2

)

(1.5

)

(0.5

)

Selling, general and administrative

 

27.9

 

33.4

 

29.0

 

35.5

 

Depreciation and amortization

 

10.5

 

9.9

 

10.8

 

11.1

 

Total operating expenses

 

109.5

 

115.0

 

111.0

 

120.9

 

Operating loss

 

(9.5

)

(15.0

)

(11.0

)

(20.9

)

Interest expense, net

 

(4.4

)

(4.7

)

(2.7

)

(4.8

)

Other income (expense), net

 

(3.4

)

2.1

 

(0.8

)

0.7

 

Income from equity method investments

 

0.1

 

0.2

 

0.2

 

0.1

 

Loss before income taxes

 

(17.2

)

(17.4

)

(14.3

)

(24.9

)

Income tax (expense) benefit

 

1.3

 

(0.3

)

1.4

 

(0.3

)

Net loss

 

(15.9

)

(17.7

)

(12.9

)

(25.2

)

Loss (income) attributable to noncontrolling interest

 

0.1

 

(0.1

)

(0.0

)

(0.1