Clean Energy Fuels Corp.
Clean Energy Fuels Corp. (Form: 10-Q, Received: 11/13/2007 14:43:43)

 

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, 2007

 

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 200, 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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer  o

 

Accelerated filer  o

 

Non-accelerated filer  x

 

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 November 1, 2007, there were 44,214,095 shares of the registrant’s common stock, par value $0.0001 per share, issued and outstanding.

 

 



 

CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES
INDEX

 

Table of Contents

 

PART I. – FINANCIAL INFORMATION

 

 

 

 

 

Item 1. – Financial Statements (Unaudited)

 

 

 

 

 

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

 

 

 

 

 

Item 3. – Quantitative and Qualitative Disclosures About Market Risk

 

 

 

 

 

Item 4. – Controls and Procedures

 

 

 

 

PART II. - OTHER INFORMATION

 

 

 

 

 

Item 1. – Legal Proceedings

 

 

 

 

 

Item 1A. – Risk Factors

 

 

 

 

 

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

 

 

 

 

 

Item 3. – Defaults upon Senior Securities

 

 

 

 

 

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

 

 

 

 

 

Item 5. – Other Information

 

 

 

 

 

Item 6. – Exhibits

 

 

1



 

PART I. – FINANCIAL INFORMATION

 

Item 1. – Financial Statements (Unaudited)

 

Clean Energy Fuels Corp. and Subsidiaries
Condensed Consolidated Balance Sheets
December 31, 2006 and September 30, 2007 (Unaudited)

 

 

 

December 31,
2006

 

September 30,
2007

 

 

 

 

 

 

 

Assets

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

937,445

 

$

74,769,017

 

Short-term investments

 

 

14,809,636

 

Accounts receivable, net of allowance for doubtful accounts of $352,050 and $470,607 as of December 31, 2006 and September 30, 2007, respectively

 

10,997,328

 

10,579,361

 

Other receivables

 

37,818,905

 

16,715,379

 

Inventories, net

 

2,558,689

 

3,780,465

 

Prepaid expenses and other current assets

 

4,862,335

 

12,102,458

 

Total current assets

 

57,174,702

 

132,756,316

 

 

 

 

 

 

 

Land, property and equipment, net

 

54,888,739

 

80,471,904

 

Capital lease receivables

 

1,412,500

 

863,250

 

Notes receivable and other long term assets

 

2,499,106

 

13,741,968

 

Goodwill and other intangible assets

 

20,957,589

 

20,930,971

 

Total assets

 

$

136,932,636

 

$

248,764,409

 

 

 

 

 

 

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Current portion of long term debt and capital lease obligations

 

$

57,499

 

$

61,958

 

Accounts payable

 

6,697,363

 

7,875,906

 

Accrued liabilities

 

5,023,051

 

7,101,027

 

Deferred revenue

 

585,505

 

557,763

 

Total current liabilities

 

12,363,418

 

15,596,654

 

 

 

 

 

 

 

Long term debt and capital lease obligations, less current portion

 

224,897

 

177,855

 

Other long term liabilities

 

1,428,464

 

1,361,912

 

Total liabilities

 

14,016,779

 

17,136,421

 

 

 

 

 

 

 

Commitments and contingencies

 

 

 

 

 

 

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

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

 

 

 

Common stock, par value $0.0001 per share. 99,000,000 shares authorized; issued and outstanding 34,192,161 shares and 44,210,245 shares at December 31, 2006 and September 30, 2007, respectively

 

3,419

 

4,421

 

Additional paid-in capital

 

181,678,861

 

295,704,376

 

Accumulated deficit

 

(60,192,221

)

(66,170,272

)

Accumulated other comprehensive income

 

1,425,798

 

2,089,463

 

Total stockholders’ equity

 

122,915,857

 

231,627,988

 

Total liabilities and stockholders’ equity

 

$

136,932,636

 

$

248,764,409

 

 

See accompanying notes to condensed consolidated financial statements.

 

2



 

Clean Energy Fuels Corp. and Subsidiaries
Condensed Consolidated Statements of Operations
For the Three and Nine Months Ended
September 30, 2006 and 2007
(Unaudited)

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2006

 

2007

 

2006

 

2007

 

 

 

 

 

 

 

 

 

 

 

Revenue

 

$

22,245,867

 

$

29,210,164

 

$

64,800,859

 

$

88,040,804

 

Operating expenses:

 

 

 

 

 

 

 

 

 

Cost of sales

 

18,237,804

 

20,252,744

 

54,933,048

 

64,100,466

 

Derivative losses

 

64,999,238

 

 

65,281,586

 

 

Selling, general and administrative

 

5,599,136

 

9,528,605

 

14,864,820

 

26,269,201

 

Depreciation and amortization

 

1,620,387

 

1,814,176

 

4,221,116

 

5,090,396

 

Total operating expenses

 

90,456,565

 

31,595,525

 

139,300,570

 

95,460,063

 

Operating loss

 

(68,210,698

)

(2,385,361

)

(74,499,711

)

(7,419,259

)

 

 

 

 

 

 

 

 

 

 

Interest income, net

 

(408,143

)

(1,414,120

)

(818,943

)

(2,253,083

)

Other expense, net

 

53,141

 

50,000

 

11,075

 

229,177

 

Loss before income taxes

 

(67,855,696

)

(1,021,241

)

(73,691,843

)

(5,395,353

)

Income tax expense (benefit)

 

(9,040,439

)

523,729

 

(10,773,775

)

582,698

 

Net loss

 

$

(58,815,257

)

$

(1,544,970

)

$

(62,918,068

)

$

(5,978,051

)

 

 

 

 

 

 

 

 

 

 

Loss per share

 

 

 

 

 

 

 

 

 

Basic

 

$

(1.72

)

$

(0.03

)

$

(2.04

)

$

(0.15

)

Diluted

 

$

(1.72

)

$

(0.03

)

$

(2.04

)

$

(0.15

)

 

 

 

 

 

 

 

 

 

 

Weighted average common shares outstanding

 

 

 

 

 

 

 

 

 

Basic

 

34,179,961

 

44,195,339

 

30,829,470

 

38,919,129

 

Diluted

 

34,179,961

 

44,195,339

 

30,829,470

 

38,919,129

 

 

See accompanying notes to condensed consolidated financial statements.

 

3



 

Clean Energy Fuels Corp.
Condensed Consolidated Statements of Cash Flows
For the Nine Months Ended September 30, 2006 and 2007
(Unaudited)

 

 

 

Nine Months Ended
September 30,

 

 

 

2006

 

2007

 

Cash flows from operating activities:

 

 

 

 

 

Net loss

 

$

(62,918,068

)

$

(5,978,051

)

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

 

 

 

 

 

Depreciation and amortization

 

4,221,116

 

5,090,396

 

Provision for doubtful accounts

 

154,730

 

1,179,600

 

Unrealized loss on futures contracts

 

8,956,599

 

 

Loss on disposal of assets

 

 

178,674

 

Deferred income taxes

 

(10,773,775

)

 

Non-cash derivative contract loss

 

64,999,238

 

 

Stock option expense

 

 

5,425,443

 

Changes in operating assets and liabilities:

 

 

 

 

 

Accounts and other receivables

 

(1,722,186

)

9,099,031

 

Inventories

 

(277,279

)

(1,221,776

)

Capital lease receivables

 

549,250

 

549,250

 

Margin deposits on futures contracts

 

(30,858,400

)

 

Prepaid expenses and other assets

 

(2,349,483

)

(9,436,235

)

Accounts payable

 

(1,434,466

)

1,269,128

 

Income taxes payable

 

(6,312,000

)

 

Accrued expenses and other

 

589,794

 

2,479,123

 

Net cash provided by (used in) operating activities

 

(37,174,930

)

8,634,583

 

 

 

 

 

 

 

Cash flows from investing activities:

 

 

 

 

 

Purchases of property and equipment

 

(11,311,061

)

(30,252,537

)

Purchase of short-term investments

 

 

(14,809,636

)

Net cash used in investing activities

 

(11,311,061

)

(45,062,173

)

 

 

 

 

 

 

Cash flows from financing activities:

 

 

 

 

 

Repayment of notes payable and capital lease obligations

 

(781,658

)

(42,583

)

Proceeds from exercise of stock options

 

8,880

 

79,142

 

Proceeds from issuance of common stock

 

21,951,788

 

110,222,603

 

Net cash provided by financing activities

 

21,179,010

 

110,259,162

 

 

 

 

 

 

 

Net increase (decrease) in cash

 

(27,306,981

)

73,831,572

 

Cash, beginning of period

 

28,763,445

 

937,445

 

Cash, end of period

 

$

1,456,464

 

$

74,769,017

 

 

 

 

 

 

 

Supplemental disclosure of cash flow information

 

 

 

 

 

Income taxes paid

 

$

6,314,029

 

$

250

 

Interest paid

 

416,852

 

80,749

 

 

 

 

 

 

 

Non-cash financing activities:

 

 

 

 

 

Margin deposits directly advanced by majority stockholder to broker under line of credit

 

$

31,055,000

 

$

 

 

See accompanying notes to condensed consolidated financial statements.

 

4



 

CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

Note 1 — General

 

Nature of Business:     Clean Energy Fuels Corp. (the “Company”) is engaged in the business of providing natural gas fueling solutions to its customers in the United States and Canada. The Company has a broad customer base in a variety of markets including public transit, refuse, airports and regional trucking. Clean Energy operates over 170 fueling locations principally in California, Texas, Colorado, Maryland, New York, New Mexico, Washington, Massachusetts, Georgia, and Arizona within the United States, and in British Columbia and Ontario within Canada.

 

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 months ended September 30, 2006 and 2007. All intercompany accounts and transactions have been eliminated in consolidation. The three and nine month periods ended September 30, 2006 and 2007 are not necessarily indicative of the results to be expected for the year ending December 31, 2007 or for any other interim period or for any future year.

 

Certain information and disclosures normally included in the notes to consolidated financial statements have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), but the resultant disclosures contained herein are in accordance with accounting principles generally accepted in the United States of America as they apply to interim reporting. The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements as of and for the year ended December 31, 2006 that are included in the Company’s Form S-1 filed with the SEC.

 

Note 2 — Cash and Cash Equivalents

 

The Company considers all highly liquid investments with maturities of three months or less on the date of acquisition to be cash equivalents. Cash and cash equivalents generally consist of cash, time deposits, commercial paper, money market funds and government and corporate debt securities with original maturity dates of three months or less. Such investments are stated at cost, which approximates fair value.

 

Note 3 — Short-Term Investments

 

Short-term investments, which are classified as “available for sale,” generally consist of commercial paper and government and commercial debt securities with original maturity dates between three and six months. Short-term investments are marked-to-market at each period end with any unrealized gains or losses included in the condensed consolidated balance sheets under the line item accumulated other comprehensive income.

 

Note 4 — Derivative Financial Instruments

 

The Company, in an effort to manage its natural gas commodity price risk exposures, utilizes derivative financial instruments. The Company often enters into natural gas futures contracts that are over-the-counter swap transactions that convert its index-based gas supply arrangements to fixed-price arrangements. The Company accounts for its derivative instruments in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities , as amended. SFAS  133 requires the recognition of all derivatives as either assets or liabilities in the consolidated balance sheet and the measurement of those instruments at fair value. The Company’s derivative instruments did not qualify for hedge accounting under SFAS  133 for the year ended December 31, 2006. As such, changes in the fair value of the derivatives were recorded directly to the consolidated statements of operations during the year. The Company did not have any futures contracts outstanding during the three or nine month periods ended September 30, 2007.

 

The Company marks to market its open futures position at the end of each period and records the net unrealized gain or loss during the period in derivative (gains) losses in the accompanying condensed consolidated statements of operations. For the nine month periods ended September 30, 2006 and 2007, the Company’s unrealized net loss amount totaled $73,955,837 and $0, respectively.

 

5



 

The Company is required to make certain deposits on its futures contracts, should any exist. At December 31, 2006 and September 30, 2007, the Company did not have any deposits outstanding as it did not have any futures contracts outstanding at the end of these periods.

 

During the nine months ended September 30, 2006 and 2007, the Company recognized realized gains of $8,674,251 and $0, respectively, related to the sales of futures contracts.

 

Note 5 — Fixed Price and Price Cap Sales Contracts

 

The Company has entered into contracts with various customers, primarily municipalities, to sell liquefied natural gas (LNG) or compressed natural gas (CNG) at fixed prices or at prices subject to a price cap. As of January 1, 2007, the Company no longer intends to enter into price cap contracts. The contracts generally range from two to five years. The most significant cost component of LNG and CNG is the price of natural gas.

 

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

 

The Company’s sales agreements that fix the price or cap the price of LNG or CNG that it sells to its customers are, for accounting purposes, firm commitments, and U.S. generally accepted accounting principles do not require or allow the Company to record a loss until the delivery of the gas and corresponding sale of the product occurs. When the Company enters into these fixed price or price cap contracts with its customers, the price is set based on the prevailing index price of natural gas at that time. However, the index price of natural gas constantly changes, and a difference between the fixed price of the natural gas included in the customer’s contract price and the corresponding index price of natural gas typically develops after the Company enters into the sales contract (with the price of natural gas having historically increased). From time to time, the Company has also entered into natural gas futures contracts to offset economically the adverse impact of rising natural gas prices (see Note 4) and, if the Company believed the price of natural gas would decline in the future, periodically sold such contracts.

 

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

 

The following table summarizes important information regarding the Company’s fixed price and price cap supply contracts under which it is required to sell fuel to its customers as of September 30, 2007:

 

 

 

Estimated
volumes (a)

 

Average
price (b)

 

Contracts
duration

 

CNG fixed price contracts

 

1,490,621

 

$

1.13

 

through 12/13

 

LNG fixed price contracts

 

17,210,187

 

$

.38

 

through 7/09

 

CNG price cap contracts

 

5,027,520

 

$

.86

 

through 12/09

 

LNG price cap contracts

 

9,663,782

 

$

.56

 

through 12/08

 

 


(a)            Estimated volumes are in gasoline gallon equivalents for CNG contracts and are in LNG gallons for LNG contracts and represent the volumes the Company anticipates delivering over the remaining duration of the contracts.

 

(b)            Average prices are in gasoline gallon equivalents for CNG contracts and are in LNG gallons for LNG contracts. The average prices represent the natural gas commodity component embedded in the customer’s contract.

 

6



 

At September 30, 2007, based on natural gas futures prices as of that date, the Company estimates it will incur between $5.0 million and $6.2 million to cover the increased price of natural gas above the inherent price of natural gas embedded in its customer’s fixed price and price cap contracts over the duration of the contracts. These estimates were based on natural gas futures prices on September 30, 2007, and these estimates may change based on future natural gas prices and may be significantly higher or lower. The Company’s volumes under these contracts, in gasoline gallon equivalents, expire as follows:

 

October 1, 2007 through December 31, 2007

 

5,490,150

 

2008

 

15,250,419

 

2009

 

2,486,896

 

2010

 

230,000

 

2011

 

230,000

 

2012

 

230,000

 

2013

 

230,000

 

 

Note 6 —Other Receivables

 

Other receivables at December 31, 2006 and September 30, 2007 consisted of the following:

 

 

 

December 31,
2006

 

September 30,
2007

 

 

 

 

 

 

 

Loans to customers to finance vehicle purchases

 

$

816,837

 

$

1,342,671

 

Advances to vehicle manufacturers

 

2,465,776

 

4,436,706

 

Fuel tax credits

 

3,810,109

 

4,016,766

 

Futures contracts deposit receivable

 

22,900,000

 

 

Income tax receivable

 

5,600,071

 

5,017,623,

 

Other

 

2,226,112

 

1,901,613

 

 

 

$

37,818,905

 

$

16,715,379

 

 

Note 7 — Land, Property and Equipment

 

Land, property and equipment, at cost, at December 31, 2006 and September 30, 2007 are summarized as follows:

 

 

 

December 31,
2006

 

September 30,
2007

 

Land

 

$

472,616

 

$

472,616

 

LNG liquefaction plant

 

12,898,178

 

12,898,178

 

Station equipment

 

36,913,552

 

42,967,572

 

LNG tanker trailers

 

8,253,415

 

11,865,380

 

Other equipment

 

6,144,553

 

6,611,031

 

Construction in progress

 

7,304,612

 

27,986,367

 

 

 

71,986,926

 

102,801,144

 

Less accumulated depreciation

 

(17,098,187

)

(22,329,240

)

 

 

$

54,888,739

 

$

80,471,904

 

 

Note 8 — Accrued Liabilities

 

Accrued liabilities at December 31, 2006 and September 30, 2007 consisted of the following:

 

 

 

December 31,
2006

 

September 30,
2007

 

Salaries and wages

 

$

1,286,196

 

$

2,635,467

 

Accrued gas purchases

 

1,566,847

 

2,376,895

 

Other

 

2,170,008

 

2,088,665

 

 

 

$

5,023,051

 

$

7,101,027

 

 

7



 

Note 9 — 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,

 

 

 

2006

 

2007

 

2006

 

2007

 

Basic and diluted:

 

 

 

 

 

 

 

 

 

Weighted average number of common shares outstanding

 

34,179,961

 

44,195,339

 

30,829,470

 

38,919,129

 

 

Certain securities were excluded from the diluted earnings per share calculations at September 30, 2006 and 2007, respectively, as the inclusion of the securities would be anti-dilutive to the calculation. The amounts outstanding as of September 30, 2006 and 2007 for these instruments are as follows:

 

 

 

September 30,

 

 

 

2006

 

2007

 

 

 

 

 

 

 

Options

 

2,414,750

 

5,720,666

 

Warrants

 

 

15,000,000

 

 

Note 10 — Comprehensive Income

 

The following table presents the Company’s comprehensive income for the nine months ended September 30, 2006 and 2007:

 

 

 

Nine Months Ended
September 30,

 

 

 

2006

 

2007

 

Net loss

 

$

(62,918,068

)

$

(5,978,051

)

Foreign currency translation adjustments

 

275,272

 

663,665

 

 

 

 

 

 

 

Comprehensive loss

 

$

(62,642,796

)

$

(5,314,386

)

 

Note 11 — Stock Based Compensation

 

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

 

 

 

Three Months Ended
September 30,

 

Nine Months Ended
September 30,

 

 

 

2006

 

2007

 

2006

 

2007

 

 

 

 

 

 

 

 

 

 

 

Stock options

 

 

 

 

 

 

 

 

 

Share-based compensation expense

 

$

 

$

1,592,789

 

$

 

$

5,425,443

 

Income tax benefit

 

 

 

 

 

Share-based compensation expense, net of tax

 

$

 

$

1,592,789

 

$

 

$

5,425,443

 

 

8



 

Stock Options

 

The following table summarizes all stock option activity during the nine months ended September 30, 2007:

 

 

 

Number
of
Shares

 

Weighted-
Average
Exercise
Price

 

 

 

 

 

 

 

Outstanding at December 31, 2006

 

2,402,250

 

$

2.97

 

Granted

 

3,337,500

 

12.17

 

Exercised

 

(18,084

)

4.38

 

Cancelled/Forfeited

 

(1,000

)

12.00

 

Outstanding at September 30, 2007

 

5,720,666

 

8.36

 

 

 

 

 

 

 

Exercisable at September 30, 2007

 

2,848,833

 

4.43

 

 

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants in 2007:

 

 

 

Nine Months Ended
September 30,
2007

 

 

 

 

 

Dividend yield

 

0.00

%

Expected volatility

 

55.00

%

Risk-free interest rate

 

4.81

%

Expected life in years

 

5.75

 

 

The weighted average grant date fair value of options granted using these assumptions was $6.81 for the nine months ended September 30, 2007.

 

Note 12 — Use of Estimates

 

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

 

Note 13 — Environmental Matters, Litigation, Claims, Commitments and Contingencies

 

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

 

From time to time, the Company may become party to legal actions arising 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.

 

As of September 30, 2007, the Company had entered into purchase commitments totaling $33.0 million related to constructing its LNG liquefaction plant in California, of which $16.8 million had been paid as of this date.

 

9



 

Note 14 — Income Taxes

 

In June 2006, the FASB issued FASB Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.” This interpretation specifies that benefits from tax positions should be recognized in the financial statements only when it is more-likely-than-not that the tax position will be sustained upon examination by the appropriate taxing authority having full knowledge of all relevant information. A tax position meeting the more-likely-than-not recognition threshold should be measured at the largest amount of benefit for which the likelihood of realization upon ultimate settlement exceeds 50 percent.

 

The Company adopted the provisions of FIN 48 on January 1, 2007. On December 31, 2006 and September 30, 2007, the Company’s liabilities for uncertain tax positions were not significant.

 

The Company’s policy is to recognize interest and penalties related to liabilities for uncertain tax benefits in the provisions for income and other taxes on the consolidated condensed statements of income. The net interest and penalties incurred were immaterial for the three and nine months ended September 30, 2006 and 2007.

 

The Company is subject to audit by tax authorities for varying periods in various tax jurisdictions. Taxable years from 2002 and 2003, respectively, are subject to audit for state and U.S. federal corporate income tax purposes. The Company is currently under audit by the State of California for tax years 2004 and 2005. Disputes may arise during the course of such audits as to facts and matters of law.

 

During June 2007, the Company requested permission from the Internal Revenue Service to change its method of accounting for its derivative gains and losses related to futures contracts that are sold in one period but relate to a subsequent period. On July 5, 2007, the Internal Revenue Service granted the Company’s request. The Company began reporting the income tax impact of the change in the third quarter of 2007. The Company anticipates that the adoption of the new method will create a federal and state alternative minimum tax liability in the amount of $825,000 for 2007, which liability will generate a corresponding alternative minimum tax credit in the same amount which can be carried forward indefinitely to offset future regular income tax liability in excess of the tentative minimum tax.

 

Note 15 — Subsequent Event

 

On October 17, 2007, the Company entered into an LNG sales agreement with Spectrum Energy Services, LLC (SES), to purchase, on a take-or-pay basis over a term of 10 years, 45,000 gallons per day of LNG from a plant to be constructed by SES in Ehrenberg, Arizona, which is near the California border.

 

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

 

The discussion in this section contains forward-looking statements. These statements relate to future events or our future financial performance. We have attempted to identify forward-looking statements by terminology such as “anticipate,” “believe,” “can,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “should,” “would” or “will” or the negative of these terms or other comparable terminology. These statements are only predictions and involve known and unknown risks, uncertainties and other factors, which could cause our actual results to differ from those projected in any forward-looking statements we make. See “Risk Factors” in Part II, Item 1A of this report for a discussion of some of these risks and uncertainties. This discussion should be read with our financial statements and related notes included elsewhere in this report.

 

We provide natural gas solutions for vehicle fleets in the United States and Canada. Our primary business activity is supplying CNG and LNG vehicle fuels to our customers. We also build, operate and maintain fueling stations, and help our customers acquire and finance natural gas vehicles and obtain local, state and federal clean air incentives. Our customers include fleet operators in a variety of markets, such as public transit, refuse hauling, airports, taxis and regional trucking.

 

Overview

 

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

 

Sources of revenue . We generate the vast majority of our revenue from supplying CNG and LNG to our customers. The balance of our revenue is provided by operating and maintaining natural gas fueling stations, designing and constructing natural gas fueling stations, and financing our customers’ natural gas vehicle purchases.

 

10



 

Key operating data . In evaluating our operating performance, our management focuses primarily on (1) the amount of CNG and LNG gasoline gallon equivalents delivered and (2) our revenue and net income (loss). The following table, which you should read in conjunction with our financial statements and notes contained elsewhere in this report, presents our key operating data for the years ended December 31, 2004, 2005 and 2006 and for the three and nine months ended September 30, 2006 and 2007:

 

Gasoline gallon equivalents
delivered (in millions)

 

Year ended
December 31,
2004

 

Year ended
December 31,
2005

 

Year ended
December 31,
2006

 

Three months
ended
September 30,
2006

 

Nine months
ended
September 30,
2006

 

Three months
ended
September 30,
2007

 

Nine months
ended
September 30,
2007

 

CNG

 

30.6

 

36.1

 

41.9

 

11.3

 

31.0

 

12.9

 

36.3

 

LNG

 

15.7

 

20.7

 

26.5

 

6.9

 

19.7

 

7.1

 

20.8

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

46.3

 

56.8

 

68.4

 

18.2

 

50.7

 

20.0

 

57.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating data

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenue

 

$

57,641,605

 

$

77,955,083

 

$

91,547,316

 

$

22,245,867

 

$

64,800,859

 

$

29,210,164

 

$

88,040,804

 

Net income (loss)

 

2,129,241

 

17,257,587

 

(77,500,741

)

(58,815,257

)

(62,918,068

)

(1,544,970

)

(5,978,051

)

 

Key trends in 2004, 2005, 2006 and the first nine months of 2007 . Vehicle fleet demand for natural gas fuels increased significantly from January 1, 2004 through the first nine months of 2007. 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. We capitalized on this growing demand by securing new fleet customers in a variety of markets, including public transit, refuse hauling, airports, taxis and regional trucking. Sales to previously existing customers also increased during these periods as they expanded their fleets.

 

The annual amount of CNG and LNG gasoline gallon equivalents we delivered increased by 48% from 2004 to 2006. The amount of CNG and LNG gasoline gallon equivalents we delivered from the first nine months of 2006 to the first nine months of 2007 increased by 13%. The increase in gasoline gallon equivalents delivered, together with generally higher prices we charged our customers due to higher natural gas prices, contributed to increased revenues during these periods. Our cost of sales also increased during these periods, which was attributable primarily to increased costs related to delivering more CNG and LNG to our customers and the increased price of natural gas.

 

Anticipated future trends . We anticipate that, over the long term, the prices for gasoline and diesel will continue to be higher than the price of natural gas as a vehicle fuel, and more stringent emissions requirements will continue to make traditional gasoline and diesel powered vehicles more expensive for vehicle fleets. We believe there will be significant growth in the consumption of natural gas as a vehicle fuel generally, and our goal is to capitalize on this trend and enhance our leadership position as this market expands. We recently began focusing on the seaports market. We are in the process of building a natural gas fueling station, and plan to build additional natural gas fueling stations that service the Ports of Los Angeles and Long Beach. We also anticipate expanding our sales of CNG and LNG in the other markets in which we operate, including public transit, refuse hauling and airport markets. Consistent with the anticipated growth of our business, we also expect that our operating costs will increase, primarily from the logistics of delivering more CNG and LNG to our customers, as well as from the anticipated expansion of our station network. We also plan to incur significant costs related to the LNG liquefaction plant we are in the initial stages of building in California. Additionally, we intend to increase our sales and marketing team as we seek to expand our existing markets and enter new markets, which will also result in increased costs.

 

Sources of liquidity and anticipated capital expenditures . In May 2007, we completed our initial public offering of 10,000,000 shares of common stock at a public offering price of $12.00 per share. Net cash proceeds from the initial public offering were approximately $108.5 million, after deducting underwriting discounts, commissions and offering expenses. Historically, our principal sources of liquidity have been cash provided by operations, capital contributions from our stockholders, our cash and cash equivalents and, during the third and fourth quarters of fiscal 2006, a revolving line of credit with Boone Pickens, a director and our largest stockholder. The line of credit was used to fund margin requirements on certain derivative contracts and was terminated in December 2006. In 2007, we expect to spend our cash primarily on building an LNG liquefaction plant in California, constructing new fueling stations, purchasing new LNG tanker trailers, financing natural gas vehicle purchases by our customers and for general corporate purposes, including making deposits to support our derivative activities, geographic expansion (domestically and internationally), expanding our sales and marketing activities, and for working capital for our expansion. For more information, see “Liquidity and Capital Resources” below.

 

11



 

Volatility in operating results related to futures contracts . Historically, we have purchased futures contracts from time to time to help mitigate our exposure to natural gas price fluctuations in current periods and in future periods. Gains and losses related to our futures activities, which appear in the line item derivative (gains) losses in our consolidated financial statements, have materially impacted our results of operations in recent periods. For the years ended December 31, 2004, 2005 and 2006 derivative (gains) losses were $(10,572,349), $(44,067,744), and $78,994,947, respectively. For the nine month periods ended September 30, 2006 and 2007, derivative losses were $65,281,586 and $0, respectively. For this reason and others, we caution investors that our past operating results may not be indicative of future results. For more information, see “Volatility of Earnings and Cash Flows” and “Risk Management Activities” below.

 

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

 

Operations

 

We generate revenues principally by selling CNG and LNG to our vehicle fleet customers. For the nine months ended September 30, 2007, CNG represented 63% and LNG represented 37% of our natural gas sales (on a gasoline gallon equivalent basis). To a lesser extent, we generate revenues by operating and maintaining natural gas fueling stations that are owned either by us or our customers. Substantially all of our operating and maintenance revenues are generated from CNG stations, as owners of LNG stations tend to operate and maintain their own stations. In addition, we generate a small portion of our revenues by designing and constructing fueling stations and selling or leasing those stations to our customers. Substantially all of our station sale and leasing revenues have been generated from CNG stations. In 2006, we also began providing vehicle finance services to our customers.

 

CNG Sales

 

We sell CNG through fueling stations located on our customers’ properties and through our network of public access fueling stations. At these CNG fueling stations, we procure natural gas from local utilities or brokers under standard, floating-rate arrangements and then compress and dispense it into our customers’ vehicles. Our CNG sales are made primarily through contracts with our fleet customers. Under these contracts, pricing is determined primarily on an index-plus basis, which is calculated by adding a margin to the local index or utility price for natural gas. We sell a small amount of CNG under fixed-price contracts and also provide price caps to certain customers on their index-plus pricing arrangement. We no longer intend to offer price-cap contracts to our customers, but we will continue to perform our obligations under price-cap contracts we entered into before January 1, 2007. Our fleet customers typically are billed monthly based on the volume of CNG sold at a station. A smaller portion of our CNG sales are on a per fill-up basis at prices we set at the pump based on prevailing market conditions. These customers typically pay using a credit card at the station.

 

LNG Sales

 

We sell substantially all of our LNG to fleet customers, who typically own and operate their fueling stations. We also sell a small volume of LNG to customers for non-vehicle use. We procure LNG from third-party producers and also produce LNG at our liquefaction plant in Texas. For LNG that we purchase from third-parties, we typically enter into “take or pay” contracts that require us to purchase minimum volumes of LNG at index-based rates. We deliver LNG via our fleet of 60 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. We also provided price caps to certain customers on the index component of their index-plus pricing arrangement for certain contracts we entered into on or before December 31, 2006. We no longer intend to offer price-cap contracts to our customers, but we will continue to perform our obligations under price-cap contracts we entered into before January 1, 2007. Our LNG contracts provide that we charge our customers periodically based on the volume of LNG supplied.

 

Government Incentives

 

From October 1, 2006 through September 30, 2009, we may receive a Volumetric Excise Tax Credit (VETC) of $0.50 per gasoline gallon equivalent of CNG and $0.50 per liquid gallon of LNG that we sell as vehicle fuel. Based on the service relationship we have with our customers, either we or our customers are able to claim the credit. We expect the tax credit will continue to factor into the price we charge our customers for CNG and LNG in the future. The legislation that created this tax credit also increased the federal excise taxes on sales of CNG from $0.061 to $0.183 per gasoline gallon equivalent and on sales of LNG from $0.119 to $0.243 per LNG gallon. These new excise tax rates are approximately the same as those for gasoline and diesel fuel.

 

12



 

The Internal Revenue Service has not issued final guidance concerning VETC as it relates to LNG sales to tax-exempt entities. Consequently, we have not recorded any benefit of VETC related to these sales in our consolidated financial statements for contracts entered into prior to October 1, 2006.

 

Operation and Maintenance

 

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

 

Station Construction

 

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

 

Vehicle Acquisition and Finance

 

In 2006, we commenced offering vehicle finance services for some of our customers’ purchases of natural gas vehicles or the conversion of their existing gasoline or diesel powered vehicles to operate on natural gas. Through these services, we loan to our customers 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 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. For the nine month period ended September 30, 2007, we generated $0.2 million of revenue from vehicle finance activities.

 

Volatility of Earnings and Cash Flows

 

Our earnings and cash flows historically have fluctuated significantly from period to period based on our futures activities, as our futures contracts to date have not qualified for hedge accounting under SFAS  133. See “Critical Accounting Policies—Derivative Activities” below. We have therefore recorded any changes in the fair market value of these contracts directly in our statements of operations in the line item derivative (gains) losses along with any realized gains or losses generated during the period. For example, we experienced derivative gains of $33.1 million for the three months ended September 30, 2005 and experienced derivative losses of $19.9 million, $0.3 million, $65.0 million and $13.7 million for the three months ended December 31, 2005, March 31, 2006, September 30, 2006 and December 31, 2006, respectively. We had no derivative gains or losses for the three months ended June 30, 2006, March 31, 2007, June 30, 2007 and September 30, 2007. Commencing with the adoption of our revised natural gas hedging policy in February 2007, we plan to structure all subsequent futures contracts as cash flow hedges under SFAS  133, but we cannot be certain that they will qualify. See “Risk Management Activities” below. If the futures contracts do not qualify for hedge accounting, we could incur significant increases or decreases in our earnings based on fluctuations in the market value of these contracts from period to period.

 

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

 

The decrease in the value of our futures positions and any required margin deposits on our futures contracts that are in a loss position could significantly impact our financial condition in the future. At September 30, 2007, we had no futures contracts outstanding and no amounts on deposit.

 

13



 

Risk Management Activities

 

A significant portion of our natural gas fuel sales are covered by contracts to sell LNG or CNG to our customers at a fixed price or a variable index-based price subject to a cap. 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. We account for sales of natural gas under these contracts as described below in “Critical Accounting Policies—Fixed Price and Price Cap Sales Contracts.”

 

Risk Management Practices Before February 2007

 

Historically, when we entered into a contract to sell natural gas fuel to a customer at a fixed price or a variable price subject to a cap, we generally sought to manage our exposure to natural gas price increases for some or all of the expected contract volumes in the natural gas futures market. We did this by purchasing futures contracts that were designed to cover the difference between the commodity portion of the price at which we were committed to sell natural gas and the price we had to pay for gas at delivery, thereby fixing the cost of natural gas we were paying. We generally purchased futures contracts covering all or a portion of our anticipated volumes in future periods.

 

From time to time, if we believed natural gas prices would decline in the future, we periodically elected to terminate futures contracts associated with fixed price or price cap customer contracts by selling the futures contracts and recognizing a gain upon such sales. When we did so, we lost future economic protections provided by the futures contracts.

 

From 2003 through 2005, we sold futures contracts covering estimated sales volumes over future periods and realized a net gain of approximately $44.8 million upon the sale of these contracts. In 2006, we disposed of certain futures contracts covering estimated sales volumes over future periods and realized a net loss of $78.7 million.

 

Our derivative activities are reflected in the line item derivative (gains) losses in our consolidated statements of operations. Two components make up this line item: (1) realized (gains) losses, and (2) unrealized (gains) losses. Realized (gains) losses represent the actual (gains) losses we realize when we sell or settle a futures contract during a period. Unrealized (gains) losses represent the (gain) or loss we record at the end of each period when we mark to market our open futures contracts at the end of each period. For realized (gains) losses on contracts sold or settled during a period, there is typically a corresponding unrealized loss (gain) on the contracts since the contracts are no longer outstanding at the end of the period and are therefore marked to zero.

 

We have a derivative committee of our board of directors and have historically conducted our futures contract activity under the advice of BP Capital L.P. (BP Capital), an entity of which Boone Pickens, our largest stockholder and a director, is the principal. Through December 31, 2006, we paid BP Capital a monthly fee of $10,000 and a commission equal to 20% of our realized gains, net of realized losses, during a calendar year relating to the purchase and sale of natural gas futures contracts. BP Capital remitted realized net gains to us, less its applicable commissions, on a monthly basis. We paid fees to BP Capital of $0.4 million in 2004, $11.7 million in 2005, $2.4 million in 2006, and $0 during the first three months of 2007. In March 2007, we amended our agreement with BP Capital to remove the 20% commission on our realized net gains during a calendar year.

 

We historically have purchased our natural gas futures contracts from Sempra Energy Trading Corp (Sempra). The futures are based on the Henry Hub natural gas price set on the New York Mercantile Exchange. One futures contract for CNG covers approximately 80,000 gasoline gallon equivalents of CNG, and one futures contract for LNG covers approximately 120,000 gallons of LNG. Each contract had historically required a deposit from us of $1,000, which is below market due to the fact that Boone Pickens had guaranteed our futures obligations to Sempra. Without this guarantee, which was cancelled March 7, 2007, we estimate the deposit amount rate will be approximately $5,000 to $12,000 per contract depending on market conditions. Additionally, without this guaranty, Sempra may terminate our contract. As of September 30, 2007, we had no futures contracts outstanding and no amounts on deposit.

 

August 2006 Purchase of Futures Contracts and December 2006 Assumption by Boone Pickens

 

On August 2, 2006, we purchased the following futures contracts and made related deposits of $9.5 million:

 

Futures settlement year

 

Volume covered by futures
(gasoline gallon equivalents)

 

2008

 

161,300,000

 

2009

 

201,625,000

 

2010

 

201,625,000

 

2011

 

201,625,000

 

 

14



 

In December 2006, Mr. Pickens assumed all of these futures contracts, together with any and all associated liabilities and obligations, in exchange for (1) the issuance to Mr. Pickens of a five-year warrant to purchase up to 15,000,000 shares of our common stock at a purchase price of $10.00 per share (which warrant was valued at $80.9 million), and (2) the assignment to Mr. Pickens of any refunds of margin deposits related to the assumed futures contracts that were made using money borrowed under the line of credit with Mr. Pickens. At the time of assumption, these futures contracts had lost $78.7 million in value. The difference between the value of the warrant and the value of the losses on the futures contracts ($2.2 million) was recorded in our statement of operations as a loss on extinguishment of derivative liability. This warrant will be dilutive to net income per share if the fair market value of our common stock exceeds $10 per share in the future.

 

Adoption of Revised Natural Gas Hedging Policy in February 2007

 

In an effort to mitigate the volatility of our earnings related to our futures contracts and to reduce our risk related to fixed-price sales contracts, our board of directors revisited our risk management policies and procedures and adopted a revised natural gas hedging policy which restricts our ability to purchase natural gas futures contracts and offer fixed-price sales contracts to our customers. Unless otherwise agreed in advance by the board of directors and the derivative committee, we will conduct our futures activities and offer of fixed-price sales contracts pursuant to the policy as follows:

 

1.              We may purchase futures contracts only to hedge our exposure to variability in expected future cash flows (such variability to be referred to hereafter as Cash Flow Variability) related to fixed-price sales contracts.

 

2.              We will purchase futures contracts in quantities reasonably expected to hedge effectively our exposure to Cash Flow Variability related to each fixed-price sales contract that we enter into after the date of the policy.

 

3.              We may offer a fixed-price sales contract to a customer only if the following three conditions are met:

 

a.              We purchase futures contracts in quantities reasonably expected to hedge effectively our exposure to Cash Flow Variability related to the fixed-price sales contract;

 

b.              We reasonably expect we will have funds sufficient: (i) to make the initial margin deposit(s) related to the intended futures contracts; and (ii) to cover estimated margin calls related to these futures contracts; and

 

c.              For any contract covering 2.5 million or more gasoline gallon equivalents of CNG or LNG per year (or any contract that, combined with previous contracts that year, would cause the total gasoline gallon equivalents contracted for to exceed 7.5 million gasoline gallon equivalents that year), we consult with the derivative committee regarding the proposed transaction, and the derivative committee approves both the offer of the fixed-price sales contract(s) and the purchase of the associated futures contracts.

 

4.              When we enter into a fixed-price sales contract according to paragraph 3 above, we will purchase sufficient futures contracts to hedge our estimated exposure to the basis differential between: (a) the price of natural gas at the NYMEX Henry Hub delivery point, and (b) the price of natural gas at the customer’s delivery point.

 

5.              If, during the duration of a fixed-price sales contract (including, without limitation, a contract signed before the adoption of this policy, a contract entered into after the adoption of this policy where futures contracts were not originally purchased to hedge the contract, and a contract that subsequently experiences a significant increase in volume that was not originally contemplated when the original futures contracts were purchased to hedge the contract), we do not have associated futures contracts in place that are sufficient to hedge effectively our estimated exposure to Cash Flow Variability related to that fixed-price sales contract, we may purchase futures contracts in quantities reasonably expected to hedge effectively our exposure to Cash Flow Variability related to that fixed-price sales contract, but only if the following two conditions are met:

 

a.              We reasonably expect we will have funds sufficient: (i) to make the initial margin deposit(s) related to the intended futures contracts; and (ii) to cover estimated margin calls related to these futures contracts; and

 

b.              For any fixed-price sales contract covering 1.5 million or more gasoline gallon equivalents per year (or any such contract that, combined with previous such contracts that year, would cause the total gasoline equivalents contracted for to exceed 5 million gasoline gallon equivalents that year), we consult with the derivative committee regarding the proposed transaction, and it approves the purchase of the futures contracts.

 

6.              When we purchase futures contracts in accordance with paragraph 5 above, we may purchase additional futures contracts to hedge our estimated exposure to the basis differential between: (a) the price of natural gas at the NYMEX Henry Hub delivery point, and (b) the price of natural gas at the customer’s delivery point.

 

15



 

7.                                        We will not sell or otherwise dispose of a futures contract during the duration of the associated fixed-price sales contract.

 

8.                                        We will attempt to qualify all futures contracts for hedge accounting as cash flow hedges under SFAS  133.

 

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

 

Critical Accounting Policies

 

Our discussion and analysis of our financial condition and results of operations is based upon our financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of financial statements requires management to make estimates and judgments that affect the reported amounts of assets and liabilities, revenue and expenses, and disclosures of contingent assets and liabilities as of the date of the financial statements. On a periodic basis, we evaluate our estimates, including those related to revenue recognition, accounts receivable reserves, notes receivable reserves, inventory reserves, asset retirement obligations, derivative values, income taxes, and the market value of equity instruments granted as stock-based compensation, among others. We use historical experience, market quotes, and other assumptions as the basis for making estimates. Actual results could differ from those estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our financial statements.

 

Revenue Recognition

 

We recognize revenue on our gas sales and for our O&M services in accordance with SEC Staff Accounting Bulletin No. 104, Revenue Recognition , which requires that four basic criteria must be met before revenue can be recognized: (1) persuasive evidence of an arrangement exists; (2) delivery has occurred and title and the risks and rewards of ownership have been transferred to the customer or services have been rendered; (3) the price is fixed or determinable; and (4) collectability is reasonably assured. Applying these factors, we typically recognize revenue from the sale of natural gas at the time fuel is dispensed or, in the case of LNG sales agreements, delivered to the customer’s storage facility. We recognize revenue from operation and maintenance agreements as we provide the O&M services.

 

In certain transactions with our customers, we agree to provide multiple products or services, including construction of and either leasing or sale of a station, providing operations and maintenance to the station, and sale of fuel to the customer. We evaluate the separability of revenues for deliverables based on the guidance set forth in EITF No. 00-21, which provides a framework for establishing whether or not a particular arrangement with a customer has one or more deliverables. To the extent we have adequate objective evidence of the values of separate deliverable items under a contract, we allocate the revenue from the contract on a relative fair value basis at the inception of the arrangement. If the arrangement contains a lease, we use the existing evidence of fair value to separate the lease from the other deliverables.

 

We account for our leasing activities in accordance with SFAS No. 13, Accounting for Leases . Our existing station leases are sales-type leases, giving rise to profit at the delivery of the leased station. Unearned revenue is amortized into income over the life of the lease using the effective interest method. For those arrangements, we recognize gas sales and operations and maintenance service revenues as earned from the customer on a volume-delivered basis.

 

We recognize revenue on fueling station construction projects where we sell the station to the customer using the completed contract method in AICPA Statement of Position 81-1, Accounting for Performance of Construction Type and Certain Production Type Contracts .

 

Derivative Activities

 

We account for our derivative instruments, specifically our futures contracts, in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities , as amended (SFAS 133). SFAS 133 requires the recognition of all derivatives as either assets or liabilities in the consolidated balance sheet and the measurement of those instruments at fair value. Our derivatives did not qualify for hedge accounting under SFAS 133 for the years ended December 31, 2004, 2005 and 2006. As such, changes in the fair value of the derivatives for the years ended December 31, 2004, 2005 and 2006, were recorded directly to our consolidated statements of operations. We determine the fair value of our derivatives at the end of each reporting period based on quoted market prices from the NYMEX. We did not have any derivative instruments during the first nine months of 2007.

 

16



 

We record gains or losses realized on our derivative instruments during the period in the line item derivative (gains) losses in our consolidated statements of operations. We also mark-to-market our open positions at the end of each reporting period with the resulting gain or loss recorded to derivative (gains) losses in our consolidated statements of operations.

 

Fixed Price and Price Cap Sales Contracts

 

Our contracts to sell CNG and LNG at a fixed price or a variable price subject to a cap are, for accounting purposes, firm commitments, and U.S. generally accepted accounting principles do not require or allow us to record a loss until the delivery of the gas and corresponding sale of the product occurs. When we enter into these fixed price or price cap contracts with our customers, the price is set based on the prevailing index price of natural gas at that time. However, the index price of natural gas constantly changes, and a difference between the fixed price of the natural gas included in the customer’s contract price and the corresponding index price of gas typically develops after we enter into the sales contract. We have entered into several contracts to sell LNG or CNG to customers at a fixed price or an index-based price that is subject to a fixed price cap. We have also generally entered into natural gas futures contracts to offset economically the adverse impact of rising natural gas prices. We have also periodically sold the underlying futures contracts related to our fixed price and price cap contracts. At September 30, 2007, we did not own any futures contracts related to our fixed price and price cap contracts. Since entering into the fixed price and price cap sales contracts, the price of natural gas has generally increased.

 

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

 

The following table summarizes important information regarding our fixed price and price cap supply contracts under which we are required to sell fuel to our customers as of September 30, 2007:

 

 

 

Estimated
volumes (a)

 

Average
price (b)

 

Contracts
duration

 

CNG fixed price contracts

 

1,490,621

 

$

1.13

 

through 12/13

 

LNG fixed price contracts

 

17,210,187

 

$

0.38

 

through 7/09

 

CNG price cap contracts

 

5,027,520

 

$

0.86

 

through 12/09

 

LNG price cap contracts

 

9,663,782

 

$

0.56

 

through 12/08

 

 


(a)                                   Estimated volumes are in gasoline gallon equivalents for CNG contracts and are in LNG gallons for LNG contracts and represent the volumes we anticipate delivering over to remaining duration of the contracts.

 

(b)                                  Average prices are in gasoline gallon equivalents for CNG contracts and are in LNG gallons for LNG contracts. The average prices represent the natural gas commodity component embedded in the customer’s contract.

 

The price of natural gas has generally increased since we entered into these contracts and fixed or capped the price of CNG or LNG that we sell to the customers. If these contracts had a notional amount as defined under GAAP, then the contracts would be considered derivatives and we would record a loss based on estimated future volumes and the estimated excess of current market prices for natural gas above the cost of the natural gas commodity component of our customer’s fixed price or price cap. However, because the contracts have no minimum purchase requirements, they are not considered derivatives and any estimated future losses under these contracts cannot be accrued in our financial statements under GAAP and we recognize the actual results of performing under the contract as the fuel is delivered. If we applied a derivative valuation methodology to these contracts using estimated volumes along with other assumptions, including forward pricing curves and discount rates, we estimate our pre-tax net income would have been lower (higher) by the following ranges for the periods indicated:

 

December 31, 2004

 

$

3,646,338

 

to

 

$

4,456,636

 

December 31, 2005

 

$

15,148,070

 

to

 

$

18,514,308

 

December 31, 2006

 

$

(14,267,259

)

to

 

$

(17,437,761

)

Nine months ended September 30, 2007

 

$

2,348,440

 

to

 

$

2,870,316

 

 

17



 

At September 30, 2007, based on natural gas futures prices as of that date, we estimate we will incur between $5.0 million and $6.2 million to cover the increased price of natural gas above the inherent price of natural gas embedded in our customer’s fixed price and price cap contracts over the duration of the contracts. These estimates were based on natural gas futures prices on September 30, 2007, and these estimates may change based on future natural gas prices and may be significantly higher or lower.

 

Our volumes under these contracts, in gasoline gallon equivalents, expire as follows:

 

October 1, 2007 through December 31, 2007

 

5,490,150

 

2008

 

15,250,419

 

2009

 

2,486,896

 

2010

 

230,000

 

2011

 

230,000

 

2012

 

230,000

 

2013

 

230,000

 

 

These amounts are based on estimates involving a high degree of judgment and actual results may vary materially from these estimates. These amounts have not been recorded in our statements of operations as they are non-GAAP.

 

Income Taxes

 

We compute income taxes under the asset and liability method. This method requires the recognition of deferred tax assets and liabilities for temporary differences between the financial reporting basis and the tax basis of our assets and liabilities. The impact on deferred taxes of changes in tax rates and laws, if any, are applied to the years during which temporary differences are expected to be settled and are reflected in the consolidated financial statements in the period of enactment. We record a valuation allowance against any deferred tax assets when management determines it is more likely than not that the assets will not be realized. When evaluating the need for a valuation analysis, we use estimates involving a high degree of judgment including projected future income and the amounts and estimated timing of the reversal of any deferred tax liabilities.

 

Our income tax benefit was $9.0 million in the quarter ended September 30, 2006, which includes an increase in the valuation allowance of $17.6 million. In the “Management’s Discussion and Analysis of Financial Condition Results of Operations — Quarterly Results of Operations” section previously filed in our initial public offering prospectus filed with the SEC on May 25, 2007, this increase in the valuation allowance was reflected in the quarter ended December 31, 2006. 

 

Stock-Based Compensation

 

Effective January 1, 2006, we account for stock options granted using Statement of Financial Accounting Standards
No. 123(R), Share-Based Payment , (SFAS 123(R))which has replaced SFAS 123 and APB 25. Under SFAS 123(R), companies are no longer able to account for share-based compensation transactions using the intrinsic method in accordance with APB 25, but are required to account for such transactions using a fair-value method and recognize the expense in the statements of operations. We adopted the provisions of SFAS 123(R) using the prospective transition method. Under the prospective transition method, only new awards, or awards that have been modified, repurchased or cancelled after January 1, 2006 are accounted for using the fair value method.

 

We accounted for awards outstanding as of December 31, 2005 using the accounting principles under SFAS 123. Under SFAS 123, for options granted before January 1, 2006, the fair value of employee stock options was estimated using the Black-Scholes option pricing model, which requires the use of management’s judgment in estimating the inputs used to determine fair value. We elected, under the provisions of SFAS 123, to account for employee stock-based compensation under APB 25 during the years ended December 31, 2004 and 2005. In the statements of operations, we recorded no compensation expense in 2004 and 2005 because the fair value of our common stock was equal to the exercise price on the date of grant of the options. Therefore, there was no “intrinsic” value to recognize in the statements of operations. However, the footnotes to our consolidated financial statements set forth in our prospectus dated May 25, 2007 (and filed with the SEC on May 25, 2007) disclose the impact on net income in 2004 and 2005 of using the grant date fair value using the Black-Scholes option pricing model.

 

As of December 31, 2005, there were no unvested stock options. Therefore, the impact of SFAS  123(R) has been reflected in the condensed consolidated statements of operations for share-based awards granted in 2006 and 2007.

 

18



 

Impairment of Goodwill and Long-lived Assets

 

We assess our goodwill for impairment at least annually (or more frequently if there is an indicator of impairment) based on Statement of Financial Accounting Standards No. 142 (SFAS 142), Goodwill and Other Intangible Assets. An initial assessment of impairment is made by comparing the fair value of the operations with goodwill, as determined in accordance with SFAS 142, to the book value. If the fair value is less than the book value, an impairment is indicated and we must perform a second test to measure the amount of the impairment. In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the operations with goodwill from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculated implied fair value of the goodwill, we will record an impairment charge. We performed our annual tests of goodwill as of December 31, 2004, 2005 and 2006, and there was no impairment indicated. There was no indication of impairment from January 1, 2007 through September 30, 2007.

 

Recently Issued Accounting Pronouncements

 

In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48), which prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. The adoption of FIN 48 did not have a material impact on our financial statements.

 

In June 2006, the FASB ratified its consensus on EITF Issue No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (EITF 06-3). The scope of EITF 06-3 includes any tax assessed by a governmental authority that is imposed concurrent with or subsequent to a revenue-producing transaction between a seller and a customer and excludes taxes that are assessed on gross receipts or that are an inventoriable cost. For taxes within the scope of this issue that are significant in amount, the consensus requires the following disclosures: (i) the accounting policy elected for these taxes and (ii) the amount of the taxes reflected gross in the income statement on an interim and annual basis for all periods presented. The consensus is effective for interim and annual periods beginning after December 15, 2006. We have historically presented sales taxes and excise taxes on sales to our customers on a net basis in our financial statements both prior to and subsequent to the adoption of EITF 06-3.

 

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements (SFAS 157), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007 and all interim periods within those fiscal years. Earlier application is permitted provided that the reporting entity has not yet issued interim or annual financial statements for that fiscal year. We are currently evaluating the impact, if any, that SFAS 157 may have on our financial statements.

 

In February 2007, the FASB issued Statement of Financial Accounting Standard No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS 159). SFAS 159 permits entities to choose to measure certain financial instruments and other eligible items at fair value when the items are not otherwise currently required to be measured at fair value. Under SFAS 159, the decision to measure items at fair value is made at specified election dates on an irrevocable instrument-by-instrument basis. Entities electing the fair value option would be required to recognize changes in fair value in earnings and to expense upfront costs and fees associated with the item for which the fair value option is elected. Entities electing the fair value option are required to distinguish, on the face of the statement of financial position, the fair value of assets and liabilities for which the fair value option has been elected and similar assets and liabilities measured using another measurement attribute. If elected, SFAS 159 will be effective as of the beginning of the first fiscal year that begins after November 15, 2007, with earlier adoption permitted if all of the requirements of SFAS 157 are adopted. We are currently evaluating the impact, if any, that SFAS 159 may have on our financial statements.

 

19



 

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,

 

 

 

2006

 

2007

 

2006

 

2007

 

Statement of Operations Data:

 

 

 

 

 

 

 

 

 

Revenue

 

100.0

%

100.0

%

100.0

%

100.0

%

Operating expenses:

 

 

 

 

 

 

 

 

 

Cost of sales

 

82.0

%

69.3

%

84.8

%

72.8

%

Derivative losses

 

292.2

%

0.0

%

100.7

%

0.0

%

Selling, general and administrative

 

25.2

%

32.6

%

22.9

%

29.8

%

Depreciation and amortization

 

7.3

%

6.2

%

6.5

%

5.8

%

Total operating expenses

 

406.6

%

108.1

%

214.9

%

108.4

%

Operating loss

 

(306.6

)%

(8.2

)%

(115.0

)%

(8.4

)%

 

 

 

 

 

 

 

 

 

 

Interest income, net

 

(1.8

)%

(4.8

)%

(1.3

)%

(2.6

)%

Other expense, net

 

0.2

%

0.2

%

0.0

%

0.3

%

Loss before income taxes

 

(305.0

)%

(3.5

)%

(113.7

)%

(6.1

)%

Income tax expense (benefit)

 

(40.6

)%

1.8

%

(16.6

)%

0.7

%

Net loss

 

(264.4

)%

(5.3

)%

(97.1

)%

(6.8

)%

 

Three Months Ended September 30, 2007 Compared to Three Months Ended September 30, 2006

 

 Revenue.     Revenue increased by $7.0 million to $29.2 million in the three months ended September 30, 2007, from $22.2 million in the three months ended September 30, 2006. This increase was primarily the result of an increase in the number of CNG and LNG gallons delivered from 18.2 million gasoline gallon equivalents in the third quarter of 2006 to 20.0 million gasoline gallon equivalents in the third quarter of 2007. One of our new transit customers (Long Island Bus, NY) and additional buses at one of our current customers (Foothill Transit, California) together accounted for 1.7 million gasoline gallon equivalents of the increase. The remaining increase in gasoline gallon equivalents delivered was due to the addition of other smaller new customers and growth from our existing customers. Revenue also increased between periods as we recorded $4.5 million of revenue related to fuel tax credits in the third quarter of 2007, which were not included in the prior period as the credits first became available in October 2006.

 

Cost of sales.     Cost of sales increased by $2.1 million to $20.3 million in the three months ended September 30, 2007, from $18.2 million in the three months ended September 30, 2006. This increase was primarily the result of an increase in costs related to delivering more CNG and LNG between periods.

 

Derivative losses.     We incurred derivative losses of $65.0 million in the three months ended September 30, 2006, related to mark-to-market losses recorded on certain futures contracts related to future periods. We incurred no derivative gains or losses during the three months ended September 20, 2007 because we did not own any derivative instruments during this period.

 

Selling, general and administrative.     Selling, general and administrative expenses increased by $3.9 million to $9.5 million in the three months ended September 30, 2007, from $5.6 million in the three months ended September 30, 2006. A significant portion of this increase related to $1.6 million of stock option expense recorded in the third quarter of 2007 associated with stock options we granted to our employees and directors in May 2007 and in September 2007. In addition, salaries and benefits increased between periods by $0.7 million, primarily related to increased salaries and compensation due to our executive officers and the hiring of additional employees. Our professional service fees increased $0.6 million between periods primarily for legal, audit and consulting services related to our status as a public company. Our bad debt expense increased $0.2 million between periods as we provided a reserve against loans made to a vehicle manufacturer during the three months ended September 30, 2007. Our business insurance costs also increased $0.2 million between periods primarily due to an increase in premiums related to our directors’ and officers’ insurance between periods.

 

Depreciation and amortization.     Depreciation and amortization increased by $0.2 million to $1.8 million in the three months ended September 30, 2007, from $1.6 million in the three months ended September 30, 2006. This increase was primarily the result of additional depreciation expense in the three months ended September 30, 2007 related to increased property and equipment balances between periods, primarily related to our expanded station network and fleet of LNG tanker trailers.

 

20



 

Interest income, net.     Interest income, net, increased by $1.0 million from $0.4 million in the three months ended September 30, 2006, to $1.4 million for the three months ended September 30, 2007. This increase was primarily the result of an increase in interest income in the three months ended September 30, 2007 due to higher average cash balances on hand in the third quarter of 2007 associated with the proceeds received from our initial public offering in May 2007.

 

Other expense, net.     There was no significant change in other expense, net, between the three months ended September 30, 2006 and the three months ended September 30, 2007.

 

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

 

Revenue.     Revenue increased by $23.2 million to $88.0 million in the nine months ended September 30, 2007, from $64.8 million in the nine months ended September 30, 2006. This increase was primarily the result of an increase in the CNG and LNG delivered between periods from 50.7 million gasoline gallon equivalents in the first nine months of 2006 to 57.1 million gasoline gallon equivalents in the first nine months of 2007. One of our new transit customers (Long Island Bus, NY) and one of our new airport customers (Los Angeles International Airport shuttle busses) together accounted for 4.1 million gasoline gallon equivalents of the increase. The remaining increase in gasoline gallon equivalents delivered was due to the addition of other smaller new customers and growth from our existing customers. Revenue also increased in the first nine months of 2007 as we recorded $12.8 million of revenue related to fuel tax credits during the period, which were not included in the prior period as the credits first became available in October 2006. We also experienced an increase between periods of $3.1 million in station construction revenue. Offsetting these increases was a decrease in our average price per gallon between periods. Our average price per gallon, excluding tax credits, was $1.25 in the first nine months of 2007, which represents a $.02 per gallon decrease from the first nine months of 2006.

 

Cost of sales.     Cost of sales increased by $9.2 million to $64.1 million in the nine months ended September 30, 2007, from $54.9 million in the nine months ended September 30, 2006. This increase was primarily the result of an increase in costs related to delivering more CNG and LNG between periods. Also contributing to the increase in cost of sales between periods is a $2.8 million increase in costs related to construction activities during the nine month period ended September 30, 2007. In addition, our cost of sales increased between periods as our average cost per gallon rose to $1.12 in the first nine months of 2007, which represents a $.04 per gallon increase over the first nine months of 2006.

 

Derivative losses.     We incurred derivative losses of $65.3 million in the nine months ended September 30, 2006, primarily related to mark-to-market losses recorded on certain futures contracts related to future periods. We incurred no derivative gains or losses during the nine months ended September 30, 2007 because we did not own any derivative instruments during this period.

 

Selling, general and administrative.     Selling, general and administrative expenses increased by $11.4 million to $26.3 million in the nine months ended September 30, 2007, from $14.9 million in the nine months ended September 30, 2006. The increase was primarily related to recording $5.4 million of stock option expense in the second and third quarters of 2007 associated with the stock options we granted to our employees and directors in May 2007 and in September 2007. There was an increase of $2.1 million in salaries and benefits between periods primarily related to the increased compensation due to our executive officers and the hiring of additional employees. Our employee headcount increased from 96 at September 30, 2006 to 118 at September 30, 2007. In addition, our rent expense increased $0.2 million between periods as we acquired additional office space between periods and our travel and entertainment expenses increased $0.4 million between periods, primarily related to increased travel related to our sales team. Our marketing expenses increased $0.9 million between periods, primarily due to certain advertising we conducted related to our refuse market segment and in the Ports of Los Angeles and Long Beach. Our bad debt expense increased $1.0 million between periods as we provided a reserve against loans made to a vehicle manufacturer and two of our vehicle financing customers during the nine months ended September 30, 2007. Our professional service fees increased $0.9 million between periods primarily for legal, audit and consulting services related to our status as a public company. Our business insurance costs also increased $0.3 million between periods, primarily due to premium increases in our directors’ and officers’ insurance between periods, and our credit card fees increased $0.2 million between periods as more of our retail customers are using credit cards to purchase their fuel.

 

Depreciation and amortization.     Depreciation and amortization increased by $0.9 million to $5.1 million in the nine months ended September 30, 2007, from $4.2 million in the nine months ended September 30, 2006. This increase was primarily related to the result of additional depreciation expense in the nine months ended September 30, 2007 related to increased property and equipment balances between periods, primarily related to our expanded station network and fleet of LNG tanker trailers.

 

21



 

Interest income, net.     Interest income, net, increased by $1.5 million from $0.8 million in the nine months ended September 30, 2006, to $2.3 million for the nine months ended September 30, 2007. This increase was primarily the result of a decrease in interest expense in the nine months ended September 30, 2007 due to the conversion of $4 million of convertible notes in April 2006, which eliminated the interest expense on these notes. In addition, interest income for the nine months ended September 30, 2007 increased in comparison to the nine months ended September 30, 2006 due to higher average cash balances on hand in the first nine months of 2007 associated with the proceeds received from our initial public offering in May 2007.

 

Other expense, net.     Other expense, net, increased by $0.2 million to $0.2 million of expense in the nine months ended September 30, 2007. The increase was primarily related to costs related to station closures recorded in the second and third quarters of 2007.

 

Seasonality and Inflation

 

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

 

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

 

Liquidity and Capital Resources

 

Historically, our principal sources of liquidity have consisted of cash provided by operations and financing activities, cash and cash equivalents, the issuance of common stock, sometimes in association with the exercise of certain warrants that were callable at our option, and in 2006 a revolving line of credit with Boone Pickens, our majority stockholder. In May 2007, we completed our initial public offering of 10,000,000 shares of common stock at a public offering price of $12.00 per share. Net cash proceeds from the initial public offering were approximately $108.5 million, after deducting underwriting discounts, commissions and offering expenses. In addition to funding operations, our principal uses of cash have been, and are expected to be, the construction of new fueling stations, the construction of a new LNG liquefaction plant in California, the purchase of new LNG tanker trailers, the financing of natural gas vehicles for our customers, and general corporate purposes, including making deposits to support our derivative activities, geographic expansion (domestically and internationally), expanding our sales and marketing activities, and for working capital for our expansion. We financed our operations in the first nine months of 2007 primarily through cash provided by operations and financing activities. At September 30, 2007, we had total cash and cash equivalents of $74.8 million compared to $0.9 million at December 31, 2006.

 

Cash provided by operating activities was $8.6 million for the nine months ended September 30, 2007, compared to cash used in operating activities of $37.2 million for the nine months ended September 30, 2006. The change in operating cash flow was primarily related to the change in our margin deposits between periods. In the first nine months of 2006, we made net margin deposits on futures contracts of $30.9 million, and in the first nine months of 2007, we received a refund of $22.9 million of margin deposits. The $22.9 million of margin deposits received in 2007 is recorded in other receivables as these deposits were transferred to other receivables in the fourth quarter of 2006 in connection with a transaction we completed with Boone Pickens in December 2006. For more information, see “Risk Management Activities – August 2006 Purchase of Futures Contracts and December 2006 Assumption by Boone Pickens” above. Offsetting this increase are (i) increases in our fuel tax credit receivable between periods, the majority of which we receive on an annual basis after we file our income tax return, and (ii) an increase between periods in the deposits we made on the production of certain LNG trucks we anticipate will be operated in the Ports of Los Angeles and Long Beach. We also experienced an increase in cash provided by operating activities between periods due to a reduction in our income taxes paid between periods of $6.3 million.

 

Cash used in investing activities was $45.1 million for the nine months ended September 30, 2007, compared to $11.3 million for the nine months ended September 30, 2006. The $33.8 million increase between periods was primarily due to increased purchases of property and equipment and increased construction in progress activity in the first nine months of 2007, including approximately $17 million that we spent on developing our LNG liquefaction plant in California. We also purchased $14.8 million of short-term investments in the third quarter of 2007 with excess cash balances.

 

22



 

Cash provided by financing activities for the nine months ended September 30, 2007 was $110.3 million, compared to cash provided by financing activities of $21.2 million for the nine months ended September 30, 2006. The $89.1 million increase between periods is primarily attributable to the net proceeds of $110.2 million we received from our initial public offering in May 2007, as compared to the proceeds of $22.0 million we received from the issuance of common stock during the nine months ended September 30, 2006.

 

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

 

We intend to fund our principal liquidity requirements through cash and cash equivalents, cash provided by operations and, if necessary, through debt or equity financings. We believe our sources of liquidity will be sufficient to meet the cash requirements of our operations for at least the next twelve months.

 

Capital Expenditures

 

We expect to make capital expenditures, net of grant proceeds, of approximately $19.3 million in 2007 to construct new natural gas fueling stations, purchase LNG tanker trailers, and for general corporate purposes. Additionally, we have budgeted approximately $65 million over the course of 2007 and 2008 to construct an LNG liquefaction plant in California which we are in the initial stages of building and anticipate will be operational in the summer of 2008. We also anticipate using $15 to $20 million from the proceeds of our initial public offering to finance the purchase of natural gas vehicles by our customers.

 

Contractual Obligations

 

The following represents the scheduled maturities of our contractual obligations as of September 30, 2007:

 

 

 

Payments Due by Period

 

Contractual Obligations:

 

Total

 

Remainder of
2007

 

2008 and
2009

 

2010 and
2011

 

2012 and
beyond

 

Capital lease obligations(a)

 

$

239,813

 

$

14,916

 

$

133,691

 

$

91,206

 

$

0

 

Operating lease commitments(b)

 

4,951,437

 

325,842

 

2,361,130

 

1,349,217

 

915,248

 

“Take-or-pay” LNG purchase contracts(c)

 

1,955,625

 

651,875

 

1,303,750

 

0

 

0

 

Construction contracts(d)

 

2,488,667

 

1,461,167

 

1,027,500

 

0

 

0

 

Other long-term contract liabilities(e)

 

16,776,106

 

12,721,757

 

4,054,349

 

0

 

0

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

26,411,648

 

$

15,175,557

 

$

8,880,420

 

$

1,440,423

 

$

915,248

 

 


(a)                                   Consists of obligations under a lease of capital equipment used to finance such equipment. Amounts do not include interest as it is immaterial.

 

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

 

(c)                                   The amounts in the table represent our estimates for our fixed LNG purchase commitments under two “take or pay” contracts. In October 2007, we entered into a 10-year take-or-pay commitment for 45,000 LNG gallons per day from an LNG plant to be constructed in Arizona, which commitment is not reflected in the table.

 

(d)                                  Consists of our obligations to fund various fueling station construction projects, net of amounts funded through September 30, 2007, and excluding contractual commitments related to station sales contracts.

 

(e)                                   Consists of our obligations to fund certain vehicles under binding purchase agreements and our commitments under binding purchase agreements we have entered into to acquire certain equipment and services related to the construction of our LNG plant in California.

 

23



 

Off-Balance Sheet Arrangements

 

At September 30, 2007, we had the following off-balance sheet arrangements:

 

                                          outstanding standby letters of credit totaling $16,000,

 

                                          outstanding surety bonds for construction contracts and general corporate purposes totaling $5.5 million,

 

                                          two take or pay contracts for the purchase of LNG,

 

                                          operating leases where we are the lessee,

 

                                          capital leases where we are the lessor and owner of the equipment, and

 

                                          firm commitments to sell CNG and LNG at fixed prices or index-plus prices subject to a price cap.

 

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

 

We have entered into contracts with two vendors to purchase LNG that require us to purchase minimum volumes from the vendors. Both of the contracts expire in June 2008. The minimum commitments under these two contracts are included in the table set forth under “Take-or-pay” LNG purchase contracts above.

 

We have entered into operating lease arrangements for certain equipment and for our office and field operating locations in the ordinary course of business. The terms of our leases expire at various dates through 2016. Additionally, in November 2006, we entered into a ground lease for 36 acres in California on which we are in the initial stages of building an LNG liquefaction plant. We have budgeted approximately $65 million over the course of 2007 and 2008 to construct this plant. The lease is for an initial term of 30 years, beginning on the date that the plant commences operations, and requires annual base rent payments of $230,000 per year, plus $130,000 per year for each 30,000,000 gallons of production capacity, subject to future adjustment based on consumer price index changes. We must also pay a royalty to the landlord for each gallon of LNG produced at the facility, as well as for certain other services that the landlord will provide. Our obligations under the lease are contingent on us obtaining the necessary permits and approvals required in the lease related to the construction and operation of the LNG liquefaction plant, which are in process. As the payments are contingent obligations, they are not included in “Operating lease commitments” in the “Contractual Obligations” table set forth above.

 

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

 

Item 3. – Quantitative and Qualitative Disclosures About Market Risk

 

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

 

Natural gas costs represented 63% of our cost of sales for 2006 and 59% of our cost of sales for the nine months ended September 30, 2007. Prices for natural gas over the seven-year and nine-month period from December 31, 1999 through September 30, 2007, based on the NYMEX daily futures data, has ranged from a low of $1.65 per Mcf to a high of $19.38 per Mcf. At September 30, 2007, the NYMEX index price of natural gas was $5.23 per Mcf.

 

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

 

24



 

We account for these futures contracts in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities . Under this standard, the accounting for changes in the fair value of a derivative depends upon whether it has been designated in a hedging relationship and, further, on the type of hedging relationship. To qualify for designation in a hedging relationship, specific criteria must be met and appropriate documentation maintained. Our futures contracts did not qualify for hedge accounting under SFAS 133 for the years ended December 31, 2004, 2005 and 2006, and changes in the fair value of the derivatives were recorded directly to our consolidated statements of operations at the end of each reporting period. We did not own any derivative instruments during the first nine months of 2007.

 

The fair value of the futures contracts we use is based on quoted prices in active exchange traded or over the counter markets. The fair value of these futures contracts is continually subject to change due to changing market conditions. The net effect of the realized and unrealized gains and losses related to these derivative instruments for the year ended December 31, 2006 was a $79.0 million decrease to pre-tax income. We did not have any futures contracts outstanding during the three or nine months ended September 30, 2007. In an effort to mitigate the volatility in our earnings related to futures activities, in February 2007, our board of directors adopted a revised natural gas hedging policy which restricts our ability to purchase natural gas futures contracts and offer fixed-price sales contracts to our customers. We plan to structure prospective futures contracts so that they will be accounted for as cash flow hedges under SFAS 133, but we cannot be certain they will qualify. For more information, please read “—Risk Management Activities” above.

 

We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to our fixed price and price cap sales contracts as of September 30, 2007. Market risk is estimated as the potential loss resulting from a hypothetical 10.0% adverse change in the fair value of natural gas prices. The results of this analysis, which assumes natural gas prices are in excess of our customer’s price cap arrangements, and may differ from actual results, are as follows:

 

 

 

Hypothetical
adverse change
in price

 

Change in
annual pre-
tax income

 

 

 

 

 

(in millions)

 

Fixed price contracts

 

10.0

%

$

(0.8

)

Price cap contracts

 

10.0

%

$

(0.7

)

 

As of September 30, 2007 we did not have any futures contracts outstanding.

 

Item 4. – Controls and Procedures

 

Disclosure Controls and Procedures

 

We maintain disclosure controls and procedures and internal controls that are designed to provide reasonable, but not absolute, assurance that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. We carried out an evaluation, under the supervision of and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report. Based on the foregoing, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective.

 

Changes in Internal Control over Financial Reporting

 

In addition, an evaluation was performed under the supervision of and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of any change in our internal control over financial reporting that has occurred during our last fiscal quarter that has materially affected, or is reasonably likely to affect materially, our internal control over financial reporting. There has been no change in our internal control over financial reporting during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

25



 

PART II. – OTHER INFORMATION

 

Item 1. – Legal Proceedings

 

We are from time to time involved in various lawsuits, legal proceedings or claims that arise in the ordinary course of business. We do not believe any such legal proceedings or claims will have, individually or in the aggregate, a material adverse effect on our business, liquidity, results of operations or financial position. However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm our business.

 

Item 1A. – Risk Factors

 

An investment in our company involves a high degree of risk. In addition to the other information included in this report, we urge you to carefully consider the risk factors set forth in our Form 10-Q for the quarter ended June 30, 2007 (filed with the SEC on August 14, 2007) in evaluating an investment in our company. We urge you to consider these matters in conjunction with the other information included or incorporated by reference in this report.

 

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

 

Use of Proceeds

 

Our initial public offering of common stock was effected through a Registration Statement on Form S-1 (File No. 333-137124) that was declared effective by the Securities and Exchange Commission on May 24, 2007. On May 31, 2007, 10,000,000 shares of common stock were sold on our behalf at an initial public offering price of $12.00 per share (for aggregate gross offering proceeds of $120.0 million) managed by W.R. Hambrecht + Co., LLC, Simmons & Company International, Susquehanna Financial Group, LLP, and NBF Securities (USA) Corp. In addition, on June 22, 2007, in connection with the exercise of the underwriters’ over-allotment option, 1,500,000 additional shares of common stock were sold by selling stockholders at the initial public offering price of $12.00 per share (for aggregate gross offering proceeds of $18.0 million). We received no proceeds from the sale of shares by selling stockholders. The offering terminated following the closing of the over-allotment sale.

 

We paid to the underwriters underwriting discounts totaling approximately $7.0 million in connection with the offering. In addition, through September 30, 2007, we incurred additional costs of approximately $4.5 million in connection with the offering, which when added to the underwriting discounts paid by us, amounts to total expenses of approximately $11.5 million. Thus, the net offering proceeds to us, after deducting underwriting discounts and offering expenses, were approximately $108.5 million through September 30, 2007. No offering expenses were paid directly or indirectly to any of our directors or officers (or their associates) or persons owning ten percent or more of any class of our equity securities or to any other affiliates.

 

Through September 30, 2007, we have used the net proceeds from the offering as follows:

 

                                          construction of our LNG liquefaction plant in California ($9.4 million),

 

                                          construction and installation of CNG and LNG stations ($1.4 million),

 

                                          financing customer vehicle purchases ($1.2 million), and

 

                                          working capital ($8.9 million).

 

The balance of the proceeds has been invested in instruments that have financial maturities no longer than nine months. We intend to use the remaining proceeds to finish building our LNG liquefaction plant in California, to build additional CNG and LNG fueling stations, to finance additional purchases of natural gas vehicles by our customers and for general corporate purposes, including making deposits to support our derivative activities, geographic expansion (domestically and internationally) and to expand our sales and marketing activities. We cannot specify with certainty all of the particular uses for the net proceeds from our initial public offering, and the amount and timing of our expenditures will depend on several factors. Accordingly, our management will have broad discretion in the application of the net proceeds.

 

Item 3. – Defaults upon Senior Securities

 

None.

 

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

 

None.

 

Item 5. – Other Information

 

None.

 

26



 

Item 6. – Exhibits

 

(a)                                   Exhibits

 

10.1*

 

Employment letter dated August 31, 2007 with Barclay Corbus

 

 

 

10.2†

 

LNG Sales Agreement between Spectrum Energy Services, LLC and Clean Energy dated October 17, 2007

 

 

 

31.1

 

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

 

 

 

31.2

 

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

 

 

 

32.1

 

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

 


*

 

Management contract or compensation plan or arrangement

 

 

 

 

Portions of this exhibit have been omitted pursuant to a request for confidential treatment and the non-public information has been filed separately with the SEC.

 

 

SIGNATURE

 

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

 

 

 

CLEAN ENERGY FUELS CORP.

 

 

 

 

Date: November 13, 2007

By:

/s/

Richard R. Wheeler

 

 

 

 

Richard R. Wheeler

 

 

 

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

 

27



 

Exhibit 10.1

August 21, 2007

 

 

 

Mr. Barclay Corbus

230 Santa Paula Avenue

San Francisco, CA 94127

 

Dear Clay:

 

I am pleased to extend to you this written offer of employment for the position of Senior Vice President, Strategic Development.

 

Title and Duties

 

We will employ you for a two year period, beginning September 10, 2007 through September 10, 2009, to perform services for Clean Energy as Senior Vice President, Strategic Development, to develop strategic growth opportunities, acquisitions, financings and other activities as described below.

 

You agree to devote all of your business time, attention and energy to the performance of your duties as Senior Vice President, subject to the direction and control of the Board of Directors and policies of Clean Energy.  This position reports to the President and CEO.  It is understood that you will reside in Northern California, but travel to the Corporate Office as needed.

 

Primary responsibility is to develop strategic opportunities for the Company utilizing your investment banking experience.  This activity may include, but not be limited to, strategic growth initiatives, acquisitions, development of various financial structures that may enhance the growth of the Company and/or add to the value of the Company.  You will be a member of the Senior Executive Management Team and will work closely with the Board of Directors, CEO, CFO, Senior VP Sales & Marketing, Senior VP Operations, and the Vice Presidents of Finance and Leasing, and Development.

 

Compensation

 

Salary and Performance Bonus

 

As compensation for your services, you will be paid an annual salary of $260,000 in equal installments on the 15 th and the last day of the month.  In addition, you will be

 

 



 

eligible for a performance bonus at the rate of 50/70/100% based on criteria set by the Compensation Committee of the Board.

 

 

Signing Bonus

 

You will receive a signing bonus of $100,000 payable on September 10, 2007.

 

 

Stock Options

 

As part of Clean Energy’s 2007 employee incentive program, you will be entitled to receive Company stock options in total of 350,000 options at market price.

 

 

Benefits

 

You will be eligible for benefits as an employee of Clean Energy on the first day of the month following your date of hire.  Clean Energy’s benefits program currently provides that Clean Energy will pay 80% of the health insurance premiums for you and your dependent(s) if you elect coverage with the Company.  Your benefits will also include four weeks of paid vacation (20 business days).  Clean Energy reserves the right to change any of its benefit programs in its sole and absolute discretion.

 

 

Reimbursement for Necessary Business Expenses

 

Clean Energy will reimburse you for reasonable and necessary business and travel expenses incurred in the performance of your duties, provided that for each business and travel expense, it is a proper deduction on the federal and state income tax return for the Company and you present Clean Energy with adequate documentation (e.g. detailed receipt or paid bill) which sets forth the date, place and amount of the expenditure, an explanation of the business purpose for the expenditure, and the names, occupations, addresses and other information sufficient to establish a business relationship to Clean Energy concerning each person who was entertained and any other documentation required in the future by the Internal Revenue Service.

 

 



 

Company Vehicle

 

The Company will provide you with a natural gas vehicle and a home refueling appliance.  You agree to maintain a valid U.S. Driver’s License and to operate any vehicle driven on company business in a safe and prudent manner and in accordance with applicable laws.

 

 

Duty Not to Compete

 

While you are employed by Clean Energy, you shall not directly or indirectly, either as an employee, employer, consultant, agent, principal, partner, stockholder, corporate officer, director, or in any other representative capacity, engage or participate in any business that is in competition in any manner whatsoever with the business of Clean Energy, its parent, subsidiary or affiliated companies.

 

 

Adherence to Company Policies

 

You agree to abide by all company policies that are issued by the company during your employment, including the following policies, which are attached and incorporated hereby reference: confidentiality policy relating to company information, and arbitration agreement.

 

 

Termination of Agreement

 

You and Clean Energy agree that either you or Clean Energy may terminate the employment relationship, at will, at any time, with or without cause.  The offer of employment is contingent upon acceptable results of a pre-employment drug screen test, a thorough background check, and an insurable motor vehicle record (MVR), all conducted by Clean Energy’s third party contractor(s).

 

 



 

If this offer is acceptable to you, please sign the included copy of this letter in the space below for your signature and Attachments 1 and 2 and return them in the enclosed self-addressed envelope.  This offer will remain in effect through September 1, 2007 and will be officially withdrawn at close of business on that day.

 

Very truly yours,

 

 

 

 

/s/ Andrew J. Littlefair

 

Andrew J. Littlefair

President and CEO

 

 

 

                I have read this letter and accept the offer of employment on the terms and conditions set forth herein.

 

 

 

Date:
  August 21, 2007
By:
/s/ Barclay Corbus
 
 
 
Barclay Corbus
 

 



 

ATTACHMENT 1

 

I will not use or disclose during or after my employment, except as authorized by Clean Energy (“Company”) in the performance of my duties, Company Information that I have or will acquire (whether or not developed by me) during my employment by Company, its predecessor companies, and their subsidiaries or any companies, joint ventures or other operations in which Company has any interest.

 

The term “Company Information” as used in this Agreement means (a) information or any item of knowledge owned, acquired, or developed by Company not generally known in the relevant trade or industry, the use of which confers a competitive advantage over those that do not use or possess it including without limitation confidential information or knowledge about Company’s products, processes, services, research, exploration, reserves, engineering, manufacturing operations, computer programs, marketing, business plans, and methods of doing business; (b) other information or knowledge in Company’s possession, whether technical, business, or financial, the use or disclosure of which might reasonably be construed to be contrary to the interest of Company; and (c) information received from third parties under confidential conditions or with a restriction on use or disclosure.

 

I agree that upon termination of my employment for any reason I will turn over to Company all tangible embodiments of Company Information that I have in my possession and my obligations not to use or disclose Company Information will continue except that when Company Information becomes generally available to the public other than by my acts or omissions, it is no longer subject to the restrictions provision.

 

 

 

Date:
  August 21, 2007
By:
/s/ Barclay Corbus

 

 

 

Barclay Corbus

 

 



 

ATTACHMENT 2

 

Any controversy, dispute or claim between any employee and the Company, or its officers, agents or other employees, shall be settled by binding arbitration, at the request of either party.  The arbitrability of any controversy, dispute or claim under this policy shall be determined by application of the substantive provisions of the Federal Arbitration Act (9 U.S.C. sections 1 and 2) and by application of the procedural provisions of the California Arbitration Act.  Arbitration shall be the exclusive method for resolving any dispute; provided, however, that either party may request provisional relief from a court of competent jurisdiction, as provided in California Code of Civil Procedure Section 1281.8.

 

The claims which are to be arbitrated under this policy include, but are not limited to claims for wages and other compensation, claims for breach of contract (express or implied), claims for violation of public policy, wrongful termination, tort claims, claims for unlawful discrimination and/or harassment (including, but not limited to, race, religious creed, color, national origin, ancestry, physical disability, mental disability, gender identity or expression, medical condition, marital status, age, pregnancy, sex or sexual orientation ) to the extent allowed by law, and claims for violation of any federal, state, or other government law, statute, regulation, or ordinance, except for claims for workers’ compensation and unemployment insurance benefits.

 

The employee and the Company will select an arbitrator by mutual agreement.  If the employee and the Company are unable to agree on a neutral arbitrator, either party may elect to obtain a list of arbitrators from the Judicial Arbitration and Mediation Service, the American Arbitration Association, or any other reputable dispute resolution organization.

 

The demand for arbitration must be in writing and must be made by the aggrieved party within the statute of limitations period provided under applicable California and/or federal law for the particular claim.  Failure to make a written demand within the applicable statutory period constitutes a waiver to raise that claim in any forum.  Arbitration proceedings will be held in Los Angeles County, California.

 

The arbitrator shall apply applicable California and/or federal substantive law to determine issues of liability and damages regarding all claims to be arbitrated, and shall apply the California Evidence Code to the proceeding.  The parties shall be entitled to conduct reasonable discovery and the arbitrator shall have the authority to determine what constitutes reasonable discovery.  The arbitrator shall hear motions for summary disposition as provided in the California Code of Civil Procedure.

 

 



 

Within thirty days following the hearing and the submission of the matter to the arbitrator, the arbitrator shall issue a written opinion and award which shall be signed and dated.  The arbitrator’s award shall decide all issues submitted by the parties, and the arbitrator may not decide any issue not submitted.  The arbitrator shall prepare in writing and provide to the parties a decision and award which includes factual findings and the reasons upon which the decision is based.  The arbitrator shall be permitted to award only those remedies in law or equity which are requested by the parties and allowed by law.

 

The decision of the arbitrator shall be binding and conclusive on the parties and cannot be reviewed for error of law or legal reasoning of any kind.  Judgment upon the award rendered by the arbitrator may be entered in any court having proper jurisdiction.

 

The cost of the arbitrator and other incidental costs of arbitration that would not be incurred in a court proceeding shall be borne by the Company.  The parties shall each bear their own costs and attorneys’ fees in any arbitration proceeding, provided however, that the arbitrator shall have the authority to require either party to pay the costs and attorneys’ fees of the other party, as is permitted under federal or state law, as a part of any remedy that may be ordered.

 

Both the Company and employees understand that by using arbitration to resolve disputes they are giving up any right that they may have to a judge or jury trial with regard to all issues concerning employment.

 

No employee or other Company representative can modify this policy in any manner nor enter into any agreement that is contrary to this policy unless it is in writing and signed by the Chief Executive Officer.  If any term, provision, covenant or condition of this policy is held by a court of competent jurisdiction or an arbitrator to be invalid, void, or unenforceable, the remaining terms and provisions of this Policy will remain in full force and effect and shall in no way be affected, impaired, or invalidated.

 

 

 

Date:
  August 21, 2007
By:
/s/ Barclay Corbus
 
 
 
Barclay Corbus

 

 


 

 


Exhibit 10.2

LNG SALES AGREEMENT

 

Between

SPECTRUM ENERGY SERVICES, LLC

An Alaska Limited Liability Company with offices at
8505 South Elwood Avenue, Building #123
Tulsa, OK 74132
Telephone: 918-298-6660
Fax: 918-298-6662

SELLER

 

and

 

CLEAN ENERGY

A California Corporation, with offices at
3020 Old Ranch Parkway, Suite 200
Seal Beach, CA 90740
Telephone: 562-493-2804
Fax: 562-546-0097

BUYER

 

 

Dated as of October 17th, 2007

Sales Agreement No: 100-07

 

 



 

TABLE OF CONTENTS

PREAMBLE

2

 

 

ARTICLE 1 DEFINITIONS

2

 

 

ARTICLE 2 TERM OF SALES AGREEMENT

3

 

 

ARTICLE 3 REPRESENTATIONS AND COVENANTS REGARDING LNG FACILITIES

3

 

 

ARTICLE 4 CONSTRUCTION OF FACILITIES

4

 

 

ARTICLE 5 LNG PLANT CAPACITY AND HOURS OF OPERATION

4

 

 

ARTICLE 6 QUALITY OF LNG

5

 

 

ARTICLE 7 DELIVERY POINT

5

 

 

ARTICLE 8 MEASUREMENT

5

 

 

ARTICLE 9 SELLER’S SHUT DOWN

6

 

 

ARTICLE 10 BUYER’S SHUT DOWN

6

 

 

ARTICLE 11 PRICE

6

 

 

ARTICLE 12 MONTHLY LIQUEFACTION CHARGE

6

 

 

ARTICLE 13 GAS COST

7

 

 

ARTICLE 14 ENERGY CHARGE

8

 

 

ARTICLE 15 BILLING AND PAYMENT

8

 

 

ARTICLE 16 TAKE OR PAY

9

 

 

ARTICLE 17 EXCLUSIVITY

10

 

 

ARTICLE 18 DEFAULT

10

 

 

ARTICLE 19 LAWS

11

 

 

ARTICLE 20 LIABILITY AND WARRANTIES

11

 

 

ARTICLE 21 TAXES

12

 

 

ARTICLE 22 FORCE MAJEURE

13

 

 

ARTICLE 23 ASSIGNMENT

13

 

 

ARTICLE 24 SEVERABILITY

14

 

 

ARTICLE 25 NOTICES

14

 

 

ARTICLE 26 MODIFICATIONS AND AMENDMENTS

15

 

 

ARTICLE 27 CONFIDENTIALITY

15

 

 

ARTICLE 28 WAIVER

15

 

 

ARTICLE 29 MISCELLANEOUS

16

 

 

ARTICLE 30 INTERPRETATION

19

 

 

ARTICLE 31 PRIOR AGREEMENTS

19

 

 

ARTICLE 32 TERMINATION

19

 

 

ARTICLE 33 DAMAGES, FEES AND COSTS

20

 

 

ARTICLE 34 MUTUAL WAIVER OF CERTAIN REMEDIES

20

 

 

ARTICLE 35 RELATIONSHIP OF THE PARTIES

21

 

 

ARTICLE 36 EXECUTION REQUIRED

21

 

 

ARTICLE 37 WAIVER OF RIGHT TO TRIAL BY JURY

21

 

 

SIGNATURE PAGE

22

 

 

EXHIBIT A WAIVER OF SOVEREIGN IMMUNITY DEFENSE; CONSENT TO JURISDICTION

23

 

1



 

LNG SALES AGREEMENT
(Sales Agreement No. 100-07)

 

THIS LNG SALES AGREEMENT (this “Sales Agreement”) is entered into as of the 17th day of October 2007 (the “Effective Date”) by and between CLEAN ENERGY , a California corporation, hereinafter referred to as “Buyer,” and SPECTRUM ENERGY SERVICES, LLC , an Alaska limited liability company, hereafter referred to as “Seller.” Buyer and Seller are sometimes hereinafter referred to, individually, as “Party” and collectively, as “Parties.”

W I T N E S S E T H :

WHEREAS, Buyer is in the business of marketing liquefied natural gas and needs additional liquefied natural gas supplies in Arizona and California in order to meet customer demand;

WHEREAS, Seller is in the business of processing natural gas and developing plants and projects that produce liquefied natural gas;

WHEREAS, Seller is the owner of certain liquefied natural gas production facilities, which when installed at or near Ehrenberg, Arizona as provided below, will have the capacity to produce a certain amount of liquefied natural gas for sale to Buyer on the terms and conditions set forth in this Sales Agreement; and

WHEREAS, Buyer desires to purchase liquefied natural gas from Seller on the terms and conditions set forth in this Sales Agreement,

NOW THEREFORE, in consideration of the covenants and provisions herein contained, Buyer and Seller do mutually agree as follows:

ARTICLE 1 DEFINITIONS

1.1                                  “Adjustment Date” shall be as defined in Article 12.2

1.2                                  “Allowed Power” shall be as defined in Article 14.

1.3                                  “BTU” shall mean British Thermal Unit and shall have the meaning as defined in the American Gas Association Report No. 3 as revised from time to time.

1.4                                  “Business Day” shall mean a day other than Saturday, Sunday or any other day when commercial banks in New York, New York are authorized or required to close.

1.5                                  “Buyer’s Shut Down” shall mean any period during which the LNG Plant is able to produce LNG, but Buyer is unable or elects not to purchase and receive LNG from the LNG Plant.

1.6                                  “Capacity,” or “Plant Capacity,” or “LNG Plant Capacity” shall mean the GPD that the LNG Plant can produce in a Day as described in Article 5.4.

1.7                                  “Day” means a period of time from 12:01 a.m. to Midnight.

1.8                                  “Delivery” or “Delivered” shall mean the transfer of LNG from the LNG Plant into Buyer’s LNG trailers at the Delivery Point.

1.9                                  “Delivery Point” shall mean the connection located on the discharge side of the loading hose at the truck loading facility at the LNG Plant.

1.10                            “Energy Charge” shall be as defined in Article 14.3.

1.11                            “Feedstock Gas” shall mean the Natural Gas delivered to the LNG Plant less any gas returned to the gas supplier.

 

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1.12                            “Gallon” or “US Gallon” shall be a measure of LNG that weighs 3.55 pounds until as determined in Article 8.1.

1.13                            “Gas” or “Natural Gas” shall mean natural gas delivered by or for Seller to the LNG Plant.

1.14                            “GPD” means Gallons per Day.

1.15                            “Liquefaction Fee” shall have the definition set forth in Article 12.1.

1.16                            “LNG” shall mean liquefied natural gas, largely made up of methane in a cryogenic liquid state.

1.17                            “LNG Plant” or “Plant” shall mean the components required to produce LNG at the Plant Capacity required pursuant to this Sales Agreement at the LNG Plant Site.

1.18                            “LNG Plant Site” shall mean the location of the LNG Plant as defined in Article 4.1.

1.19                            “Market Risk” shall mean Buyer’s risk of not being able to successfully sell LNG to end users or others at all or at a particular price.

1.20                            “MCF” shall mean one thousand (1,000) cubic feet.

1.21                            “MMBTU” shall mean one million (1,000,000) British Thermal Units.

1.22                            “MMCF” shall mean one million (1,000,000) cubic feet.

1.23                            “Month” shall mean a calendar month.

1.24                            “Monthly Liquefaction Charge” shall have the definition set forth in Article 12.1 below.

1.25                            “Natural Gas Provider” shall mean the vendor of Natural Gas which supplies the Feedstock Gas.

1.26                            “Sales Agreement Year” shall mean a period of twelve (12) consecutive Months commencing on the first day of the first Month following the initial delivery of LNG from Seller to Buyer, except that the period from the initial delivery of LNG to the first day of the following Month shall be included in the first Sales Agreement Year.

1.27                            “Seller’s Shut Down” shall mean any period in excess of four (4) hours in duration during which Seller is unable to produce LNG at the LNG Plant.

1.28                            “Take or Pay” shall have the definition set forth in Article 16.1 below.

ARTICLE 2 TERM OF SALES AGREEMENT

2.1                                  This Sales Agreement shall be deemed operative and in full force and effect from and after the Effective Date and shall remain operative and in full force and effect for a primary term of ten (10) Sales Agreement Years, unless earlier terminated pursuant to the terms of this Sales Agreement (the “Primary Term”).  Upon expiration of the Primary Term, this Sales Agreement shall automatically renew on a year-to-year basis (each year, a “Renewal Term”) until terminated by either Party at the end of the Primary Term or any subsequent Renewal Term upon at least one hundred and eighty (180) days prior written notice to the other Party.  The Primary Term and all Renewal Terms are collectively referred to herein as the “Term.”

ARTICLE 3 REPRESENTATIONS AND COVENANTS REGARDING LNG FACILITIES

3.1                                  Seller represents and warrants that it is the owner of certain LNG Plant equipment. Seller agrees to install, maintain, and operate the LNG Plant in good safe operating condition, in accordance with generally accepted industry practices and the terms of Article 4 below.

 

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3.2                                  Buyer represents that it currently has LNG trailers, LNG storage facilities and marketing and distribution systems in place and available for the receipt, collection, distribution and marketing of LNG at and from the Delivery Point at Seller’s LNG Plant to Buyer’s customers or marketing distribution points (the “Buyer System”).

3.3                                  Other representations or warranties are set forth elsewhere in this Sales Agreement.

ARTICLE 4 CONSTRUCTION OF FACILITIES

4.1                                  Upon execution of this Sales Agreement, Seller shall commence and complete with due diligence the construction and installation of the LNG Plant at or within fifteen miles of Ehrenberg, Arizona  (the “LNG Plant Site”).

4.2                                  Within 30 days following execution of this Sales Agreement, Seller shall deliver to Buyer a construction schedule with a start-up date for the LNG Plant of July 1, 2008 (the “Start-up Date”).

4.3                                  Seller will promptly notify Buyer upon reaching certain milestones to be set forth in the construction schedule.  These milestones shall include the following:  1) Execution of a ground lease between Seller and the land owner; 2) Application for construction permits and other authorizations from governmental authorities required for construction and operation of the LNG Plant (collectively, “Permits”); 3) Receipt of construction Permits from governmental authorities for the LNG Plant; 4) Installation of LNG Plant foundations; 5) Installation of electrical power to the LNG Plant; 6) Setting of key LNG Plant components; 7) Installation of LNG storage tanks; 8) Completion of interconnecting piping; 9) Completion of electrical and instrumentation systems; 10) Completion of integrity testing; 11) Completion of Gas supply interconnecting piping with the Gas Supplier; 12) Functional check out of LNG Plant operation; and 13) Issuance of Certificate of Occupancy or the equivalent thereof authorizing commencement of operation of the LNG Plant.

ARTICLE 5 LNG PLANT CAPACITY AND HOURS OF OPERATION

5.1                                  The LNG Plant will be designed to have and will have the Capacity to produce a minimum of 50,000 GPD. However, initially, the LNG Plant may produce fewer than 50,000 GPD due to insufficient electrical power being available from Arizona Public Service Co. (“APS”), the electricity provider to the LNG Plant.  Seller will make commercially reasonable efforts to cause the LNG Plant to produce 50,000 GPD beginning on July 1, 2008, although it shall not be in default of this Sales Agreement if its failure or inability to do so is due to a lack of electrical power from APS.  In no event, however, shall the LNG Plant produce fewer than 20,000 GPD during the period from July 1, 2008 to June 30, 2009.

5.2                                  On and after July 1, 2009, regardless of available electric power supplied by APS, the LNG Plant will produce a minimum of 50,000 GPD.

5.3                                  Prior to the Start-Up Date, Seller will provide prompt written notice to Buyer of anticipated changes in Plant Capacity and keep Buyer promptly apprised of issues it is dealing with regarding Plant Capacity and power availability. After the Start Up Date of the LNG Plant, Plant Capacity will be determined by demonstration over a 24-hour period pursuant to the procedure described in Article 5.4 below. Prior to Start Up Date, Plant Capacity will be determined by thermodynamic modeling.

5.4                                  Seller will arrange for a Plant Capacity test and provide Buyer five (5) Business Days prior written notice of the test to enable Buyer to be present, the first of which shall occur within three (3) months after Plant startup.  Subsequent tests can be requested by Buyer and will be performed within 10 days of the request.  To administer the test, Seller will operate the Plant in a normal mode over a seventy-two (72) hour period during which Plant production will be recorded every twelve (12) hours. The Plant Capacity will be determined by taking the average hourly production over the 72-hour period and multiplying the hourly average by 24.

 

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                                                Subsequent changes in Plant Capacity will be calculated the same way as the initial Plant Capacity test.

5.5                                  Buyer and Seller shall use commercially reasonable efforts to regulate the Delivery in quantities, at times and in a manner that prevents LNG stored at the LNG Plant from exceeding 100,000 Gallons at any time.

5.6                                  Seller will use commercially reasonable efforts to regulate its production schedule so that LNG produced by the LNG Plant will be available for Delivery at as much of a uniform rate of flow as is practicable.

5.7                                  Subject to Seller Shut Downs, the LNG Plant shall be operational 24 hours per Day and Buyer may take Delivery at any time during the time the LNG Plant is operating.

ARTICLE 6 QUALITY OF LNG

6.1                                  The LNG Delivered at the Delivery Point hereunder, shall:

(a)                                   be free of solids, sand, salt, dust, gums, crude oil, and other objectionable substances which may be injurious to facilities and systems designed for LNG use;

(b)                                  contain not more than one mole percent (1%) of ethane;

(c)                                   contain at least ninety-seven mole percent (97%) of methane;

(d)                                  contain not more than three mole percent (3%) of nitrogen;

(e)                                   when delivered to the loading pumps, the LNG will have a saturation pressure not to exceed 15 PSIG; and

(f)                                     be free of odor.

ARTICLE 7 DELIVERY POINT

7.1                                  Delivery of LNG purchased by Buyer hereunder from Seller shall be made at the Delivery Point.  As part of Seller’s obligation to construct the LNG Plant, Seller, at its cost, will install facilities sufficient to enable Buyer’s personnel to operate and pump LNG into Buyer’s LNG trailers.

ARTICLE 8 MEASUREMENT

8.1                                  The unit of measurement for LNG delivered under this Sales Agreement shall be one Gallon of LNG. Unless otherwise stated, all quantities given herein are in terms of such unit. For the purposes of this Sales Agreement, each such Gallon shall weigh 3.55 Pounds until actual LNG produced from the Plant is analyzed to determine the composition and the weight of one US Gallon. The computations used to determine the actual weight in Pounds per Gallon and Gallons per MMBTU will be performed by CHI Engineering Co. or another third party engineering firm mutually agreed upon using Gas Processors and Suppliers Association (GPSA) standards.

8.2                                  Seller shall calibrate its truck scale on an annual basis. If either Party, at any time, desires a special test of the scale, it will promptly notify the other Party, and the Parties will then cooperate to secure a calibration test and a joint observation of any adjustments, if such adjustments are necessary. If the scale is accurate upon calibration to within 2%, the Party who requested the test will pay for the calibration test. If, upon calibration, the scale equipment is found to be inaccurate by two percent (2%) or more, Seller shall pay the cost of the test and registrations thereof shall be corrected at the rate of such inaccuracy for any period which is definitely known and agreed upon, but in the case the period is not definitely known and agreed upon, then for a period extending back one half (1/2) of the time elapsed since the last date of

 

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                                                calibration or 3 months whichever is shorter. The amount of inaccuracy, if over 2%, will be invoiced or credited to the appropriate Party within 10 days. Following any test, scale equipment found inaccurate shall immediately be restored as closely as possible to a condition of accuracy. If, for any reason, the scale is out of service or out of repair so that the amount of LNG delivered cannot be ascertained or computed from the reading thereof, the LNG delivered during the period such scales are out of service, or out of repair, shall be transported to an agreed upon alternative truck scale.

8.3                                  Seller’s scale shall be of sufficient quality to be approved and certified by the local governmental agency having jurisdiction over weights and measures.  Seller will provide detailed information to Buyer about the scale prior to acquiring the scale for installation into the LNG Plant and provide Buyer with the option of paying Seller to upgrade the scale to a model preferred by Buyer that can weigh individual truck axle groupings as well as total truck weights.  Seller will provide Buyer seven (7) days to determine if it wishes to pay for such an upgrade.  In the event Buyer elects to pay for said upgrade, it will become the property of Seller.

8.4                                  Buyer anticipates that it will be able to recover LNG vapors from its LNG trailers upon their arrival at the LNG Plant for delivery.  Buyer and Seller will cooperate in developing a method of transferring such vapor to the LNG Plant and measuring the volume of LNG derived from such vapor recovery, for which volume Buyer shall receive a credit against Buyer’s payments to Seller under Article 15.1.

ARTICLE 9 SELLER’S SHUT DOWN

9.1                                  The LNG Plant is engineered to operate 345 Days per year. Seller will provide Buyer with at least one Month advance notice in writing of any planned Seller’s Shut Down in any Month.  Buyer will provide Seller with its preferred schedule for Delivery at the Delivery Point.  Buyer acknowledges that there will only be one (1) loading rack and scale at the LNG Plant and that it will thus not be possible to load multiple trucks simultaneously and agrees to take such fact into account in developing its LNG Delivery schedules. The Parties will cooperate to make the scheduled Seller’s Shut Downs coincide with times that are as convenient as practicable for Buyer.

9.2                                  In the event of an unscheduled Seller’s Shut Down due to mechanical problems, interruption in electricity supply or Natural Gas supply or any Force Majeure condition, Seller will immediately notify Buyer of the circumstances, and provide sufficient details to Buyer. Seller will keep Buyer promptly apprised of any change in status of Seller’s Shut Down.

9.3                                  In the event that for any reason, other than a Default by Buyer or Seller’s Shut Down not exceeding ten (10) Days, Seller is unable or unwilling to operate the LNG Plant, Buyer shall have the right, but not the obligation, to operate the LNG Plant as an independent contractor, until such time as Seller is able or willing, as the case may be, to operate the LNG Plant.  In such event, Buyer shall be entitled to reimbursement of its reasonable costs of operating the LNG Plant, which reimbursement shall be by way of offset against Buyer’s payments to Seller under Article 15.

ARTICLE 10 BUYER’S SHUT DOWN

10.1                            In the event that Buyer, for whatever reason(s), other than Force Majeure, elects not to take LNG from the Plant or to take less than Plant Capacity for a prolonged period, Buyer will give as much advance written notice to Seller as reasonably possible under the circumstances of its intention to discontinue taking LNG from the Plant or to take less than Plant Capacity, and the anticipated duration of discontinuance or reduction.  Buyer will be responsible for taking away any remaining LNG product stored at the Plant.  Under these circumstances Buyer shall be subject to its Take or Pay Monthly Quantity pursuant to Article 16 below.

 

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ARTICLE 11 PRICE

11.1                            Subject to all of the terms and conditions of this Sales Agreement, Buyer shall pay Seller the sum of (1) the Monthly Liquefaction Charge, (2) the Gas Cost of the natural gas purchased in accordance with Article 13, and (3) the Energy Charge to produce the LNG, as defined in Article 14.

ARTICLE 12 MONTHLY LIQUEFACTION CHARGE

12.1                            The initial liquefaction fee is [***] per Gallon of LNG Delivered to Buyer (the “Liquefaction Fee”).  The “Monthly Liquefaction Charge” shall mean the Liquefaction Fee times the number of Gallons delivered to Buyer during a Month.

12.2                            On January 1, 2009 and on January 1st of each subsequent year during the Term of this Sales Agreement (each, an “Adjustment Date”), the Liquefaction Fee shall be subject to an annual adjustment. The annual adjustment shall be equal to the percentage change, upward or downward, in [***] (the “Index”), during the one-year period ending on the applicable Adjustment Date; provided, however, in no event shall any such annual adjustment exceed [***] and in no event shall the Liquefaction Fee be less than the amount specified in Article 12.1. For example, the first such adjustment shall be effective as of January 1, 2009 based on the change in the Index from January 1, 2008 through January 1, 2009 as described above and subject to the foregoing limitations.

ARTICLE 13 GAS COST

13.1                            Seller shall make arrangements for the purchase of Feedstock Gas for the Plant. Seller will propose its preferred method of purchasing the Feedstock Gas to Buyer including, without limitation, how it will be priced and any other terms associated with acquiring the Feedstock Gas.  Buyer will be provided with a thirty (30) day period within which to object to the purchase method and propose an alternative.  In such event, the Parties shall negotiate in good faith to agree upon the Feedstock Gas purchase method to be implemented and used by Buyer that will provide the quantities of Feedstock Gas needed by Seller to satisfy its obligations under this Sales Agreement at the lowest total cost practicable.  In the absence of any objection and proposed alternative by Buyer within such 30-day period, Seller will execute the purchase arrangements proposed as Seller’s preferred method and Buyer will reimburse Seller for the cost of purchased Feedstock Gas.  In the event the parties cannot agree upon the purchase method, Buyer shall be responsible for obtaining at its sole cost and expense Feedstock Gas for the LNG Plant and for delivering the same thereto in sufficient quantities to allow Seller to satisfy its obligations under this Sales Agreement in accordance with and subject to Article 13.2 below.  Unless Buyer pays the supplier of the Feedstock Gas, the quantity of purchased Feedstock Gas for which Seller will be reimbursed will be determined by the weights from the scale readings used to calculate the LNG sales volume and shall exclude any Feedstock Gas that is lost or combusted in the LNG production process. The costs to be reimbursed shall include not only the cost for the volume of Feedstock Gas converted to LNG as described above, but also the transportation costs, metering and blending charges and all other costs associated with purchasing the Feedstock Gas and having it delivered to the LNG Plant (said cost of Feedstock Gas and such other costs collectively, the “Gas Cost”).  In the event of a Take or Pay situation based on a Buyer’s Shut Down, the Gas Cost will also include any penalty, take or pay charges, transportation charges and/or other fees or charges Seller has to pay for not taking the Feedstock Gas.

13.2                            In the event Buyer wishes to make its own arrangements for Natural Gas deliveries to the LNG Plant and pay directly for this Natural Gas supply, it shall provide Seller with no less than sixty (60) days prior written notice of its intent to do so.  As part of such notice, Buyer will propose to Seller its preferred method of purchasing the Gas, how it will be priced and delivered to the Plant, and any other terms associated with acquiring the Gas.  Seller will have a thirty (30) day period to object to the purchase method if it believes that the proposed arrangement will adversely affect its ability to perform its obligations under this Sales Agreement.  In such event,

 

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                                                the Parties shall negotiate in good faith to agree upon the Natural Gas purchase arrangement to be entered into by Buyer that will provide the quantities of Natural Gas needed by Seller to satisfy its obligations under this Sales Agreement.  In the absence of any objection by Seller within such 30-day period, Buyer shall execute the purchase arrangements proposed and give written notice to Seller of the date on which the new arrangement will be implemented so that Seller may cancel Seller’s existing purchase agreements.  Seller shall reimburse Buyer for any gas consumed in the LNG production process at a price not to exceed Buyer’s supply Gas Cost.  Any early termination penalties or other costs that Seller may incur due to its cancellation of gas purchase agreements or other arrangements and substitution of Buyer’s new arrangement will be reimbursed by Buyer within thirty (30) calendar days after Seller’s invoice(s) therefore. If Buyer elects to supply Natural Gas pursuant to this Article, Buyer will arrange for and pay directly for all transportation, metering and blending charges and other gas acquisition costs associated with said volume of Natural Gas, and Buyer will indemnify and hold Seller harmless from any and all claims, losses, liability, costs or expenses associated with the supply of Gas to the Plant unless attributed to the Seller or to a Force Majeure.  In the event of a Seller’s Shut Down, Seller will indemnify and hold Buyer harmless from any and all claims, losses, liability, costs or expenses associated with the supply of Gas to the Plant including any penalty, take or pay charges, transportation charges and/or other fees or charges Buyer has to pay for not taking the Natural Gas unless due to a Force Majeure event.

ARTICLE 14 ENERGY CHARGE

14.1                            In addition to the other charges payable by Buyer to Seller under this Sales Agreement, Buyer shall pay to Seller an Energy Charge on a monthly basis.  The method used to calculate the amount of the Energy Charge will be identical to the method used by Arizona Public Service Company (APS) as if APS had delivered the “Allowed Power” during the subject month.

14.2                            The Allowed Power has two components: (1) the quantity of power delivered measured in kilowatt hours (kwh), which will be calculated by multiplying the Gallons delivered in the subject month by [***] and (2) the monthly power demand as measured in kilowatts (kw), which shall be determined by multiplying [***] for the subject month by [***].  For the purposes of calculating the monthly power demand, Plant Capacity will not exceed 50,000 Gallons per day without Buyers prior written approval.

14.3                            The Energy Charge will be calculated by multiplying each of the respective Allowed Power components, as calculated in accordance with Article 14.2, by the applicable rates for Transmission Service contained in Arizona Public Service Company’s (APS) Rate Schedule [***], or as amended from time to time and approved by the Arizona Corporation Commission or its successor, and the Energy Charge will also include all other adjustments, assessments, charges and taxes that APS is required to charge its customers under the Transmission Service contained in its Rate Schedule [***] or, as amended from time to time and approved by the Arizona Corporation Commission or its successor..

14.4                            If APS changes its demand charge structures, then both Parties will negotiate a new Energy Charge in a manner that is consistent with Article 14.1.

ARTICLE 15 BILLING AND PAYMENT

15.1                            On or before the 15th day of each Month, Seller shall render to Buyer an invoice showing the number of Gallons of LNG delivered to Buyer at the Delivery Point during the preceding calendar Month and the amount due to Seller according to the measurement, terms, conditions and price herein provided. The invoice will separately identify and include the number of delivered Gallons, Take or Pay Gallons, if any, Monthly Liquefaction Charge, Gas Cost, Energy Charge for the previous Month, and Conditioning Fees, if any. In the case of the Energy Charge, information in the invoice will include the current published APS rates applicable to the respective month.  Buyer will provide Seller with the form Buyer desires Seller to use in generating the invoice prior to the start up of the LNG Plant.

 

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15.2                            In the event Buyer supplies the Natural Gas to the Plant in accordance with Article 13.2, Buyer  shall invoice Seller for the difference between what Buyer was charged for the Natural Gas and the quantity of Natural Gas condensed into LNG and Delivered for the subject month.  Seller shall pay the invoice in accordance with Article 15.4.

15.3                            Seller will install an enclosed, air conditioned room that will be close to the truck loading facility so that Buyer can install point of sale systems that will produce a bill of lading for each load of LNG Delivered.  Seller will provide scale weight indicators and data so Buyer may interface it with Buyer’s systems.  Seller will provide composition of the LNG to be loaded so Buyer’s system can also utilize this data.  Seller shall provide Buyer with loading controls such that Buyer’s system will have to authorize any and all Deliveries.  Buyer’s system will produce a duplicate bill of lading for each Delivery that will be kept by Seller at the LNG Plant for a period of 24 months.

15.4                            All invoices will be paid within thirty (30) calendar days of the invoice date by electronic funds transfer to invoicing Party’s bank account the amount as shown on the above mentioned invoice. In the event either Party disputes any portion of the amount on the invoice, said Party shall pay those amounts not in dispute and notify the other Party in writing of the details associated with the disputed amount no later than fifteen (15) days after the invoice date.

15.5                            In the event an error is discovered in the amount shown to be due in any invoice such error shall be adjusted without interest or penalty as soon as reasonably possible; provided, however, any invoice shall be final as to both Parties unless written notice of an error in such invoice is given by a Party to the other Party within one (1) year after payment therefore has been made. Such notice shall be effective when received by the Party to which such notice is sent.

15.6                            In the event a Party fails to pay all of the amount of any invoice, as set forth in Articles 15.1, 15.2, and 15.4 above, upon written notice from the invoicing Party to the other Party, the other Party shall have ten (10) days to cure the Default condition.  Upon the other Party’s failure to cure the Default condition, the invoicing Party shall have the right to (a) require payment in advance of each Delivery, or (b) withhold and set off payment of any amounts of monies due or owing by Seller to Buyer, whether in conjunction with this Sales Agreement or otherwise, against any and all amounts due or owing by Buyer to Seller under this Sales Agreement, or (c) suspend or discontinue services until such amount is paid, or (d) terminate this Sales Agreement. In addition, in the event an invoice is not paid within the time set forth in Article 15.4, the undisputed invoice balance will accrue a late fee of one percent (1%) of the undisputed balance for each month payment is late. The exercise by the invoicing Party of any of these options shall not preclude the invoicing Party from pursuing any other available remedy in equity or at law. The prevailing Party shall be entitled to claim recovery pursuant to Article 33.2.

15.7                            Seller and Buyer shall each preserve all records pertaining to this Sales Agreement, including all test and measurement data and charts, and all test equipment calibration records for a period of at least two (2) years, or longer as shall be required under law or regulation.  Each Party, or its designated representative shall have access to the books and records of the other Party upon reasonable notice during regular business hours to the extent such records are applicable to the quality, measurement, billing, pricing and quantities of LNG delivered hereunder.

ARTICLE 16 TAKE OR PAY

16.1                            It is recognized that (a) Seller is making a considerable financial investment in the capital cost of the LNG Plant and a financial return is required and Seller is relying solely on Buyer’s commitments and obligations under this Sales Agreement for such return and that Seller is granting an exclusive marketing arrangement to Buyer pursuant to this Sales Agreement; (b)

 

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                                                Seller would not undertake the cost of building the LNG Plant were it not for Buyer’s agreement as set forth herein to agree to purchase the entire Plant Capacity.  Therefore, Buyer agrees to pay Seller for the Take or Pay Monthly Quantity regardless of Buyer’s ability to take Delivery of the Take or Pay Monthly Quantity of LNG and thus, the Market Risk is fully assumed by Buyer by its execution of this Sales Agreement.  In the event Buyer for any reason, other than Force Majeure, fails to take delivery of the Take or Pay Monthly Quantity of LNG from Seller, where the Plant Capacity was available to be taken, Buyer will pay Seller an amount equal to (1) the Liquefaction Fee multiplied by the Take or Pay Monthly Quantity, (2) the actual demand charge and other fixed, monthly charges from APS, and (3) any unavoidable Gas Costs related to the shortfall of LNG gallons taken below the Take or Pay Monthly Quantity.  Buyer agrees that the Take or Pay Monthly Quantity for each Month shall be equal to the number of days in such Month multiplied by 45,000 GPD (the “Take or Pay Monthly Quantity”).  By way of example, if a particular Month contains thirty (30) days, the Take or Pay Monthly Quantity for such Month would be (30 days X 45,000 GPD) or 1,350,000 Gallons.  Take or Pay shall apply when the LNG Plant is not experiencing a Seller’s Shut Down, and the Plant Capacity is available to produce LNG and Buyer does not take Delivery of its Take or Pay Monthly Quantity for reasons other than a Force Majeure, Buyer must pay Seller as if Buyer had taken Delivery of the Take or Pay Monthly Quantity of LNG, subject to the provisions of this Article 16.

16.2                            Notwithstanding Article 16.1 above, at times when the quality of LNG delivered by Seller does not meet the specifications set forth in Article 6, Buyer shall only be required to purchase and take delivery of fifty percent (50%) of the Take or Pay Monthly Quantity during such period, but in no case shall Buyer be required to take Delivery of LNG that is less than 92 mole percent methane and not more than 4 mole percent ethane but otherwise meets the specifications listed in Article 6.  In such event, Seller shall have the right to sell the quantities of the off specification LNG not purchased by Buyer to others. Buyer agrees to use its commercially reasonable efforts to market all of the Plant Capacity during such upset periods and Seller agrees to use  commercially reasonable efforts to resolve the composition issue and deliver LNG meeting the specifications set forth in Article 6.1 as soon as practicable.  Both Parties recognize that the composition of the Feedstock Gas might vary from time to time and there is a remote chance that the Feedstock Gas may be too ethane rich for the Plant to remove it to less than the one mole percent (1%) level.

16.3                            Notwithstanding Article 16.1 above, in the event of a Seller’s Shut Down, Buyer is relieved from any Take or Pay liability during the actual period of the Seller’s Shut Down or a Force Majeure event and during the first twenty-four (24) hours after the LNG Plant is restarted.

16.4                            In the event that the Plant Capacity is less than 50,000 GPD as determined in accordance with Article 5.4 or as agreed to by the Parties, the Take or Pay Quantity of 45,000 GPD in Article 16.1 will be reduced on a pro rata basis.

ARTICLE 17 EXCLUSIVITY

17.1                            Seller is constructing the LNG Plant for the purpose of dedicating to Buyer all of the Plant’s Capacity for the term of the Sales Agreement and, subject to exceptions set forth in this Sales Agreement, that it will sell all LNG produced at the Plant to Buyer pursuant and subject to the terms and conditions of this Sales Agreement. Buyer agrees to purchase all of the Plant’s LNG production, not to exceed 45,000 GPD. As such, it is agreed that no LNG will be marketed from this Plant to other parties without the express written permission of Buyer, except as otherwise provided in this Sales Agreement and unless Buyer is in Default. In the event of a Default, as defined in Article 18, by Buyer, Seller shall use commercially reasonable efforts to sell LNG to others.

17.2                            Upon execution of this Sales Agreement, Seller will advise other entities with which it has communicated within the ninety (90) days preceding the Effective Date regarding the sale of LNG by the LNG Plant, that Seller has entered into an exclusive arrangement for the sale of

 

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                                                LNG to Buyer and at Buyer’s option, will advise those entities of Buyer’s identity so they may contact Buyer if interested in purchasing LNG. Except as otherwise permitted pursuant to the terms of this Sales Agreement, Seller will make no further marketing efforts other than during the 180 day period prior to the expiration of this Sales Agreement, in the event notice is given by either Party not to extend the term of this Sales Agreement as provided in Article 2.1 above.

ARTICLE 18 DEFAULT

18.1                            Seller’s rights upon a payment default by Buyer are set forth in Article 15 above.  Subject to Article 15 and notwithstanding any other provision herein, a Party to this Sales Agreement (the “Defaulting Party”) shall be in default of this Sales Agreement if the Defaulting Party shall (a) default in the payment or performance of any material obligation to the Party not in default (the “Non-defaulting Party”) under this Sales Agreement, and such default shall continue for thirty (30) days after notice of such default from the Non-defaulting Party to the Defaulting Party (or such longer period if such default cannot be cured within such 30-day period provided that the Defaulting Party promptly commences curing within such 30-day period and thereafter pursues the same with due diligence until completion); (b) file a petition or otherwise commence or authorize the commencement of a proceeding or case under any bankruptcy, reorganization, or similar law for the protection of creditors or have any such petition filed or proceeding commenced against it; (c) otherwise become bankrupt or insolvent (however evidenced); (d) be unable to pay its debts as they fall due by acceleration or otherwise; or (e) fails to give adequate security for, or assurance of, its ability to perform its obligations hereunder within ten (10) days of a reasonable request therefore from the Non-defaulting Party (each a “Default”).

18.2                            Upon the occurrence of a Default described above, and for so long as such Default is continuing, the Non-defaulting Party shall, in addition to all other rights and remedies available to the Non-defaulting Party set forth elsewhere in this Sales Agreement, shall have the right to exercise any and all rights and remedies available under applicable law.

18.3                            This Article 18 shall be without prejudice and in addition to any right of termination, setoff, combination of accounts, lien, or other right to which  the Non-defaulting Party is at any time otherwise entitled (whether by operation of law, contract, or otherwise).

ARTICLE 19 LAWS

19.1                            This Sales Agreement shall be subject to, and each Party shall perform its obligations hereunder in compliance with, all valid and applicable laws, orders, rules and regulations made by duly constituted governmental authorities. The interpretation and performance of this Sales Agreement shall be governed and construed in accordance with the laws of the State of Texas, excluding any conflict of law principles which may apply to the laws of another jurisdiction.

ARTICLE 20 LIABILITY AND WARRANTIES

20.1                            Buyer’s Liability for Possession and Control of LNG . As between Buyer and Seller hereto, Buyer shall be deemed to have title to and be in control and possession of all LNG delivered by Seller under this Sales Agreement upon Delivery thereof by Seller to Buyer at the Delivery Point.  From and after such delivery at the Delivery Point, Buyer will be fully responsible and liable for any and all LNG loss, damages, injuries, claims, actions, expenses and liabilities, including reasonable attorney’s fees caused or resulting from Buyer’s handling, transportation and sale of LNG following Delivery and Buyer shall release, indemnify, defend and hold Seller harmless from and against any and all claims, suits, judgments, damages, losses, liability and expenses on account of the foregoing matters for which Buyer is responsible.

20.2                            Seller’s Liability for possession and Control of Natural Gas and/or LNG . As between Seller and Buyer hereto, Seller shall have title and/or custody to and be in control and possession of any Natural Gas and/or LNG from and after the time such Natural Gas is received at the Plant and until the LNG is Delivered to Buyer at the Delivery Point.  Until Delivery at the Delivery Point, Seller will be fully responsible and liable for any and all Natural Gas and/or LNG loss, damages,

 

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                                                injuries, claims, actions, expenses and liabilities, including reasonable attorney’s fees caused by or resulting from the Natural Gas or LNG and Seller shall release, indemnify, defend and hold Buyer harmless from and against any and all claims, suits, judgments, damages, losses, liability and expenses on account of the foregoing matters for which Seller is responsible.

20.3                            Notwithstanding the foregoing provisions of this Article 20, neither Party shall be required to indemnify the other Party for the other Party’s own negligence.

20.4                            Limitation of Liability . Except when necessary to provide indemnity against a third party claim pursuant to an indemnification obligation of a Party under this Sales Agreement and subject to the Take or Pay obligations set forth in Article 16, neither Party shall be liable to the other for incidental consequential, special, direct, punitive, or exemplary damages.

20.5                            Warranty of Title . Seller warrants that it will, at the time of Delivery of LNG hereunder, deliver said LNG free and clear of all liens, encumbrances, and claims whatsoever, except for Seller’s rights to receive payment therefore pursuant to this Sales Agreement and except to the extent caused by Buyer’s purchases of Natural Gas for the Plant pursuant to the terms of this Sales Agreement. Except as set forth in this Article, Seller shall indemnify, save, and hold Buyer, its subsidiaries and/or affiliates, and their directors, officers, employees, and agents, free and harmless from all suits, actions, debts, accounts, damages, costs, losses, and expenses, including reasonable attorney’s fees, arising from or out of a breach of the warranty contained in this Article 20.5.

20.6                            Disclaimer of Warranties . EXCEPT AS SPECIFICALLY SET FORTH IN THIS SALES AGREEMENT, SELLER MAKES ABSOLUTELY NO OTHER WARRANTIES, EXPRESS OR IMPLIED, INCLUDING, WITHOUT LIMITATION, THOSE OF MERCHANTABILITY AND OF FITNESS FOR A PARTICULAR PURPOSE, WITH RESPECT TO THE LNG PLANT OR LNG PRODUCED AND SOLD PURSUANT TO THIS SALES AGREEMENT OR AS TO ANY OTHER MATTER, ALL OF WHICH ARE HEREBY DISCLAIMED.  UNDER NO CIRCUMSTANCES SHALL SELLER, ITS OFFICERS, AGENTS, EMPLOYEES, PRINCIPALS, PARENT OR AFFILIATE BE LIABLE FOR ANY DAMAGE TO ANY EQUIPMENT WHICH SHALL BE OPERATED USING THE LNG PROVIDED HEREUNDER. THE LIABILITY OF SELLER FOR ANY BREACH OF THIS ARTICLE 20.6 SHALL BE LIMITED TO THE REPLACEMENT VALUE OF ANY LNG AND SUCH REASONABLE AND CUSTOMARY TRUCK TRANSPORT COSTS, AS MAY BE INVOLVED IN A DISPUTE.  IN NO INSTANCE SHALL SELLERS UNINSURED LIABILITY FOR THE TOTAL OF ALL SUCH AMOUNTS EXCEED $25,000.00 PER DELIVERY. THE PARTIES SHALL ENDEAVOR TO MITIGATE DAMAGES HEREUNDER.

20.7                            Buyer’s Knowledge of Product, Odorization, and Indemnity . BUYER HEREBY EXPRESSLY REPRESENTS THAT BUYER IS FAMILIAR WITH THE PROPERTIES OF LNG AND NATURAL GAS, AND BUYER AGREES TO INFORM BUYER’S CUSTOMERS, AGENTS, EMPLOYEES, AND/OR PURCHASER(S) OF THE SAME. THE LNG PROVIDED HEREUNDER WILL NOT BE STENCHED AND/OR ODORIZED BY SELLER AND BUYER CERTIFIES, REPRESENTS AND WARRANTS THAT ODORIZATION IS NOT REQUIRED FOR DELIVERY OF LNG TO BUYER UNDER THIS SALES AGREEMENT. BUYER SHALL BE RESPONSIBLE FOR ODORlZlNG THE LNG AFTER DELIVERY IN ORDER TO COMPLY WITH ANY ODOR STANDARDS CONTAINED IN APPLICABLE REGULATIONS, RULES OR LAW . AS SET FORTH ABOVE, BUYER SHALL BE DEEMED TO BE IN EXCLUSIVE POSSESSION AND CONTROL OF THE LNG ONCE BUYER HAS TAKEN DELIVERY AND BUYER ASSUMES ALL RESPONSIBILITY FOR SAFE HANDLING OF THE LNG PROVIDED HEREUNDER FROM THE TIME OF SAID DELIVERY. BUYER SHALL FULLY PROTECT, INDEMNIFY, AND DEFEND SELLER, AND ITS OFFICERS, AGENTS, EMPLOYEES, PRINCIPALS, INSURERS AND PARENT, AND HOLD IT HARMLESS FROM ANY AND ALL CLAIMS, LOSSES, DAMAGES, DEMANDS, SUITS, CAUSES OF ACTION AND LIABILITIES

 

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                                                (INCLUDING ALL REASONABLE ATTORNEY FEES AND EXPENSES) INCURRED BY OR IMPOSED UPON ARISING, DIRECTLY OR INDIRECTLY, FROM BUYER’S FAILURE TO PROPERLY ODORIZE AND/OR TO EITHER MONITOR OR MAINTAIN ODORIZATION AT OR ABOVE APPLICABLE ODOR STANDARDS OR SO NOTIFY BUYER’S CUSTOMERS, AGENTS, AND/OR EMPLOYEES.

20.8                            Mutual Indemnity for Negligence or Willful Misconduct .  Each Party (the “Indemnifying Party”) shall release, indemnify, defend and hold the other Party and such other Party’s affiliates, parents and subsidiaries and their respective shareholders or other equity owners, directors, managers, officers, employees and agents harmless from and against any and all claims, suits, judgments, damages, losses, liability and expenses arising out of or resulting from the negligence or willful misconduct of the Indemnifying Party or the Indemnifying Parties employees, contractors, agents or invitees.

ARTICLE 21 TAXES

21.1                            None of the fees or charges set forth and described in this Sales Agreement shall be deemed to include any tax. Buyer shall bear sole responsibility and liability for payment of any taxes associated with the purchase, transportation, use, sale or resale of LNG. If Seller is required to pay any tax (other than income tax, property tax, or normal enterprise taxes), Buyer shall promptly reimburse Seller for same upon Seller’s demand, in addition to the other fees and charges provided for in this Sales Agreement. Where applicable, Seller agrees to take receipt of such tax and process same with the appropriate tax authority. Buyer shall be required to provide Seller with proof, satisfactory to the appropriate tax authority, of any and all tax exemptions Buyer may claim, Buyer shall provide Seller with all records and information, satisfactory to the appropriate tax authority, regarding Buyer’s disposition of all LNG delivered hereunder. [***].

ARTICLE 22 FORCE MAJEURE

22.1                            Neither Seller nor Buyer shall be liable to the other for failure, whether in whole or in part to perform or comply with any obligation or condition of this Sales Agreement caused by an event of force majeure which, for purposes of this Sales Agreement shall include, without limitation blockades; embargoes; insurrections; riots; epidemics; flood; washouts; landslides; mudslides; earthquakes; extreme cold or freezing weather; lightning, civil disturbances; failure to prevent or settle any strike; fire; explosions; breakdown or failure or accident to machinery, method of transport or line of pipe, or the order of any court or governmental authority having jurisdiction, war; acts of the public enemy; terrorism; espionage; nuclear disaster; act of God; fire; severe weather; earthquakes; floods; material shortage or unavailability at reasonable cost not resulting from the failing Party’s failure to timely place orders or take other necessary actions therefore; inability or delay in obtaining governmental permits; government codes, ordinances, laws, rules, regulations, or restrictions; or any other cause, whether similar or dissimilar to those above mentioned (excluding, however, any obligation to make payments of monies due hereunder), which is beyond the reasonable control of the Party claiming relief under this provision and which by the exercise of due diligence such Party is unable to prevent or overcome (each, a “Force Majeure Event”). The settlement of strikes and lockouts shall be entirely within the discretion of the Party experiencing the same.

22.2                            Force Majeure Events shall not relieve a party of liability to the extent such causes are the result of the negligence of such Party or in the event of its failure to use all commercially reasonable efforts to remedy the situation, nor shall such causes or contingencies affecting such performance relieve either Party from its obligations to make payments of amounts then due in respect of Feedstock Gas and/or LNG already delivered. For the avoidance of doubt, should Seller’s provision of services or supply of LNG depend in whole or in part upon production from a Plant which is damaged or destroyed, Seller shall not be obliged to repair or rebuild such Plant in order to fulfill the terms of this Sales Agreement.

 

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22.3                            A Party claiming relief under this Article 22 shall promptly notify the other Party in writing of the event preventing its performance stating facts supporting such claim of inability to perform.  Thereupon, the obligation to deliver or receive the quantities so affected shall be suspended during the continuation of an inability so caused, but for no longer period, this Sales Agreement shall otherwise remain unaffected.

ARTICLE 23 ASSIGNMENT

23.1                            Either Party may assign or otherwise convey any of its rights, titles, or interests under this Sales Agreement to an affiliate of such party or joint venture in which the assigning Party owns a 100% equity interest, without prior approval, but with notice to the other Party; provided that no such assignment shall relieve the assigning Party of its obligations under this Sales Agreement. Either Party may assign or otherwise convey any of its rights, titles or interests to any third party provided it has obtained the prior written consent of the other Party hereto, which consent shall not be unreasonably withheld, conditioned or delayed, however, Buyer may unreasonably withhold approval of any sale or transfer to any person or business previously or currently in the natural gas vehicle industry.  No assignment of this Sales Agreement by Buyer shall release Buyer or any guarantor from liability under this Sales Agreement unless the assignee’s and any replacement guarantor possess creditworthiness acceptable to Seller, as determined in Seller’s sole and absolute discretion.  Notwithstanding the foregoing, the obligations set forth in Article 29 shall run with the LNG Plant and the land upon which it is situated and be the obligation of the party owning the LNG Plant.

23.2                            Notwithstanding the provisions of Article 23.1, any assignment to a tribe of American indians or any affiliate thereof, shall be subject to and conditioned upon the receipt by Buyer of a waiver of sovereign immunity substantially in the form attached hereto as Exhibit A.

ARTICLE 24 SEVERABILITY

24.1                            Should any section, paragraph, subparagraph, or other portion of this Sales Agreement be found invalid or be required to be modified by a court or government agency having jurisdiction, then only that portion of this Sales Agreement shall be invalid or modified.

                                                The remainder of this Sales Agreement which is still valid and unaffected shall remain in force. If the absence of the part that is held to be invalid, illegal, or unenforceable, or modification of the part to be modified, substantially deprives a Party of the economic benefit of this Sales Agreement, the Parties shall negotiate reasonable and valid provisions to restore the economic benefit to the Party deprived or to balance the Parties’ obligations consistent with the intent reflected in this Sales Agreement. If the Parties are unable to do so, either Party may terminate this Sales Agreement by giving the other Party notice of termination not later than sixty (60) days after the effective date of the order, rule, or regulation so affecting this Sales Agreement. Seller shall also have the right to terminate this Sales Agreement as provided above in the event either the services performed by Seller, or facilities utilized by Seller become subject to regulation which substantially deprives Seller of the economic benefit of this Sales Agreement.

ARTICLE 25 NOTICES

25.1                            Any notice, request, demand, statement, invoice or payment provided for in this Sales Agreement or any notice which a Party may desire to give to the other shall be in writing and shall be, except as otherwise specifically set forth herein, considered as duly delivered (i) as of the date of transmittal if sent by email to the other Party’s email address as set forth below and mailed by certified mail return receipt required (postage prepaid) to the other Party’s address as set forth below, (ii) telecopied (with answer-back confirmation of receipt to the other Party’s fax address as set forth below), or (iii) courier expressed to the other Party at the address set forth below:

 

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NOTICES TO BUYER :

CLEAN ENERGY
3020 Old Ranch Parkway, Suite  200
Seal Beach, CA 90740
Attention:   Chief Operating Officer and
                     Chief Financial Officer
Telephone: 562-493-2804
Fax: 562-546-0097
Email: mpratt@cleanenergyfuels.com and rwheeler@cleanenergyfuels.com

NOTICES TO SELLER :

SPECTRUM ENERGY SERVICES, LLC
8505 South Elwood Avenue, Building #123
Tulsa, OK 74132
Attention:   President-Managing Member
Telephone: 918-298-6660
Fax: 918-298-6662
Email: ray@latchem.com

PAYMENTS AND STATEMENTS TO SELLER :

SPECTRUM ENERGY SERVICES, LLC
8505 South Elwood Avenue, Building #123
Tulsa, OK 74132
Attention:   President-Managing Member
Telephone: 918-298-6660
Fax: 918-298-6662
Email: ray@latchem.com

25.2                            Either Party may change any of its addresses shown above by notifying the other Party, in accordance with the notice provisions above, of such change.

ARTICLE 26 MODIFICATIONS AND AMENDMENTS

26.1                            Any change, modification, amendment or alteration of this Sales Agreement shall be in writing, signed by the Parties hereto, and no course of dealing between the Parties shall be construed to alter the terms hereof, except as expressly stated herein.

ARTICLE 27 CONFIDENTIALITY

27.1                            The Parties understand and agree that the terms and conditions of this Sales Agreement, all documents referenced herein or exchanged between the Parties and all communications between the Parties regarding this Sales Agreement are considered as being confidential or proprietary (collectively, “Confidential Information”) as between the Parties, and shall not, without the other Party’s prior written consent, be disclosed to any third party, corporation or entity, except  (i) to Affiliates, legal, accounting and other professional advisors, provided that such Party shall be liable under this Article for any such Affiliate’s or any such legal, accounting or other professional advisor’s failure to comply with the terms hereof; (ii) as may be required by governmental authority or court; (iii) as may be necessary to enforce the terms of this Sales Agreement, as provided below.  As a condition of its consent to disclosure of Confidential Information by the other Party as required above, a Party may require redaction of portions of this Sales Agreement or other document containing Confidential Information.  Notwithstanding the foregoing, nothing herein contained shall prevent a Party or its parent or other Affiliate from complying with state and federal securities laws, including without limitation, the filing of this

 

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                                                Sales Agreement as an exhibit to a filing by the parent of Buyer with the Securities and Exchange Commission under the Securities Exchange Act of 1934.

27.2                            Information will not be deemed Confidential Information if it (i) is or becomes publicly available other than through the actions of the receiving Party; (ii) was previously known to or is independently developed by the receiving Party free of any obligation to keep it confidential; or (iii) was previously disclosed or becomes available to the receiving Party without restriction from a third party whose disclosure did not or does not violate any confidentiality obligation.  Seller acknowledges that Buyer owns and operates a plant that produces liquefied natural gas and is familiar with all aspects of the production of LNG.  A Party shall be excused from these nondisclosure provisions if the disclosure is required by law, rule, regulations or governmental authority or to the extent required for a Party to undertake or defend an action brought by one Party in court to enforce the terms of this Sales Agreement against the other Party.  In the event that a Party is requested or required by law, rule, regulation or governmental authority or court to disclose any Confidential Information of the other Party, it is agreed that it shall provide the other Party prompt notice of such request so that an appropriate protective order may be sought by the affected Party. It is understood that the Party requesting a protective order shall bear all costs related thereto.

27.3                            Each Party shall have the right to review and approve any publicity material, press releases or other public statements by the other that refer to such Party or that describe any aspect of this Sales Agreement.  Each Party agrees not to issue any such publicity materials, press releases, or public statements without the prior written approval of the other party, unless the information has already been made public by the other party, except as is required by the Party or its parent or other Affiliate to comply with federal or state securities laws.  Neither Party shall publish or use any advertising, sales promotions or other publicity materials that use the other Party’s logo, trademarks or service marks without the prior written approval of the other Party, which may be withheld in a Party’s sole discretion.

ARTICLE 28 WAIVER

28.1                            The failure of Seller or Buyer at any time to require performance by the other Party of any provision hereof shall in no way affect the right of either Party to require any performance which may be due thereafter pursuant to such provision, nor shall the waiver by Buyer or Seller of any breach of any provision hereof be taken or held to be a waiver of any subsequent breach of such provision.

ARTICLE 29 MISCELLANEOUS

29.1                            Conditioning Fee . Buyer shall pay Seller a conditioning fee to take Delivery with a Warm Trailer. Such fee shall be equal to [***] per Delivery into a Warm Trailer (the “Conditioning Fee”).  As used herein, “Warm Trailer” means an LNG trailer that is warmer than minus 230 degrees Fahrenheit (-230°F).

29.2                            Delivery into a Warm Trailer . Buyer shall use its commercially reasonable efforts to bring each LNG trailer to the Delivery Point with the temperature inside its LNG storage tank(s) not greater than -230 degrees F.  When Buyer desires to take Delivery of LNG with a Warm Trailer, Buyer shall contact Seller to agree on a date and time when Buyer shall take such Delivery. In the event that Buyer arrives at the Delivery Point to take Delivery of LNG with a Warm Trailer without Seller having agreed on a date and time for such Delivery, Seller will arrange Delivery as soon as Seller determines that it can accommodate such Delivery. Seller shall require Buyer to pay Seller the Conditioning Fee set forth in this Sales Agreement to take Delivery with a Warm Trailer. Seller shall not be liable for any damage that may occur as a result of the Delivery of LNG into a Warm Trailer.

29.3                            Personal Protective Equipment . Buyer shall ensure that, prior to taking Delivery, all truck operator(s) shall have been provided appropriate personal protective equipment, including, but

 

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                                                not limited to, flame retardant clothing fully covering the arms, legs and torso, sturdy leather work shoes (not athletic type), apron, hard hat, gloves, splash-proof safety goggles, and facial shield. Buyer shall ensure that, while inside the Plant, including the Delivery point area, the truck operator(s) shall at all times, wear such personal protective equipment and comply with Seller’s Plant safety requirements. While Seller reserves the right to deny Delivery to any person observed not using all appropriate personal protective equipment, Seller has no obligation to observe or ensure that all appropriate personal protective equipment is used.

29.4                            Training . Buyer shall ensure that all truck operator(s) have received instruction in Seller’s truck loading procedures prior to taking Delivery of LNG at Plant. Buyer shall provide no less than one (1) Business Day notice of the arrival of any truck operator(s) that shall require such instruction. Plant personnel shall endeavor to provide instruction in a timely manner upon arrival of the truck. Buyer will cause training to be provided to the truck operator(s) regarding the hazards of handling LNG and the precautions to take to safely load LNG. Buyer shall ensure that while inside the Plant, including the LNG Delivery Point area, the truck operator(s) shall at all times act in compliance with such training and precautions. While Seller reserves the right to deny Delivery to any person not using the truck loading facilities in the proper manner, Seller has no obligation to observe that the truck loading facilities are being used in the proper manner.  Seller acknowledges that Buyer may engage an independent truck operator to haul Buyer’s LNG trailers.  Seller shall provide training to its employees and independent contractors in the proper operation and maintenance of an LNG plant.

29.5                            Insurance . Buyer and Seller shall maintain in force and effect throughout the term of this Sales Agreement, insurance coverage of the types and in the amounts set forth below, which may be under blanket policies, with insurance companies reasonably acceptable to either Party whose acceptance shall not be unreasonably withheld. If either Party violates this provision, the other Party may, at its option and without prejudice to its other legal rights, terminate this Sales Agreement upon reasonable notice.  The limits set forth below are minimum limits and shall not be construed to limit either Party’s liability. All costs and deductible amounts will be for the sole account of each Party for maintaining its own coverage.

Worker’s Compensation Insurance, complying with the laws of any state having jurisdiction over each employee, and employer’s liability insurance with limits of $1,000,000 for each accident, $1,000,000 for each disease for each employee, and a $1,000,000 disease policy limit.

Commercial or comprehensive general liability insurance on an occurrence form with a combined single limit of $1,000,000 for each occurrence, and annual aggregates of $1,000,000 for bodily injury and property damage, including coverage for blanket contractual liability, broad form property damage, personal injury liability, independent contractors, products/completed operations, and the explosion exclusion shall be deleted.

Automobile liability insurance with a combined single limit of $1,000,000 for each accident for bodily injury and property damage, to include coverage for all owned, non-owned, and hired vehicles.

Excess or umbrella liability insurance with a combined single limit of $1,000,000 for each occurrence, and annual aggregates of $1,000,000 for bodily injury and property damage covering the excess of employer’s liability insurance and the insurance set forth above.

29.5.1                   In each of the policies described above, each Party agrees to waive, and will require each of its insurers to waive, any rights of subrogation or recovery it may have against the other Party, their parents, subsidiaries, or affiliated companies to the extent of the indemnity obligations. Each Party shall name the other Party as an additional insured under the policies described above to the extent of the indemnity obligations.

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29.5.2                   The policies described above will include the following amendment. “This insurance is primary insurance with respect to Seller, its parents, subsidiaries and affiliated companies, and any other insurance maintained by Seller, its parents, subsidiaries, or affiliated companies is excess and not contributory with this insurance,” but only to the extent of liabilities of Buyer not otherwise indemnified under this Sales Agreement and for any indemnities assumed by Buyer under this Sales Agreement.

29.5.3                   Non-renewal or cancellation of policies described above shall be effective only after the other Party shall have received thirty (30) days prior written notice of such non-renewal or cancellation. Prior to the creation of any obligation on the part of Seller to Deliver any LNG hereunder, Buyer shall provide Seller, and Seller shall provide Buyer, with certificates of insurance on an Accord 25 or 25S form evidencing the existence of the insurance coverage required.

29.5.4                   Buyer may self-insure for any of the coverage requested herein provided Buyer has an investment grade credit rating. In the event of self-insurance, the following conditions shall apply: (1) Such self-insurance program shall provide levels of coverage that are equivalent to or greater than the amounts required by this Article either by itself or in combination with any insurance policies that might be purchased; (2) Coverage provided by such self-insurance shall be as broad as the most current ISO forms(s) issued for like or same coverage; (3) Buyer can provide reasonable proof that it has made adequate financial arrangements to fund such self-insurance program; (4) Such self-insurance is permitted by any applicable law; and (5) Such self-insurance shall comply with all the “additional insured” and “waiver of subrogation or recovery” terms and conditions in this Article as if insurance policies had been issued.

29.6                            Right of First Refusal.   Before the Start-up Date, Seller may assign all rights and obligations of this Sales Agreement to a newly created company (“NEWCO”) which will be created to own and manage the LNG Plant and Seller shall own 100% of NEWCO.  This assignment will be permitted and is not subject to a Right of First Refusal (“ROFR”) described in this Article 29.6, provided that in such event, NEWCO shall be subject to the ROFR described in this Article 29.6, and all other obligations of Seller under this Sales Agreement.  In the event Seller or NEWCO wishes to transfer ownership or partial ownership in the Plant or an equity interest in NEWCO or Seller, or the ultimate parent of Seller, if any, such transaction will be subject to the ROFR.  A sale by one partner of Seller or NEWCO of part or all of its ownership interest in Seller or NEWCO to another partner(s) of Seller or NEWCO shall not be subject to the ROFR described below.

29.6.1                   Subject to the immediately preceding paragraph, in the event that Seller seeks to transfer all or part of its interest in the LNG Plant, whether such transfer is structured as an asset sale or a sale of a controlling equity interest in Seller (whether such sale is a single sale or a series of transfers), Seller shall include with the transfer notice delivered in accordance with Article 25 a written right of first refusal notice (a “ROFR Notice”).  Each ROFR Notice shall set forth the proposed transferee’s name and shall include a summary of the terms of the proposed transfer, including without limitation, the purchase price and method of payment, and shall have attached to it a copy of any offer or counteroffer executed or to be executed by Seller and the transferee.  Seller represents and warrants that the purchase price, terms and conditions referred to in the ROFR Notice shall have been arrived at through arm’s length negotiations.  Buyer agrees that any ROFR Notice and the terms therein or attached thereto shall be considered Confidential Information of Seller and shall be subject to Article 26 above.

29.6.2                   If Buyer, within thirty (30) days after receipt of a ROFR Notice, indicates in writing to Seller its agreement to purchase the LNG Plant to be transferred on the terms stated in such ROFR Notice, Seller shall sell and convey such property to Buyer on the same terms and conditions as set forth in such ROFR Notice,.  If Buyer does not notify Seller of its intent to exercise its right of first refusal within such thirty (30) day period, or if Buyer gives Seller written notification that it does not elect to exercise such right of first refusal, then Seller may transfer the LNG Plant free of

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                                                this right of first refusal on the same terms and conditions offered to Buyer as set forth in the ROFR Notice.

29.6.3                   If Seller does not complete the transfer of the LNG Plant described within the ROFR Notice within sixty (60) days of (i) the expiration of the aforementioned thirty (30) day period or (ii) such earlier date on which Buyer notifies Seller that it does not wish to exercise its right of first refusal, or if Seller intends to transfer the LNG Plant on terms and conditions which are changed or modified from those stated in the ROFR Notice, then the transaction or any further transaction shall be deemed a new determination by Seller to transfer the LNG Plant and the provisions of this Article 29.6 shall again be applicable to any proposed transfer.

29.6.4                   Buyer’s right of first refusal as provided herein shall be extinguished if and only if Buyer fails to exercise its right to purchase the LNG Plant within the thirty (30) day period provided above and Seller thereafter transfers the LNG Plant to the transferee and on the terms set forth in the ROFR Notice within the sixty (60) day period provided above, and provided the offer from the transferee presented to Buyer in the ROFR Notice was a valid, bona fide and binding third party offer.  Failure by Buyer to respond to any other offer shall in no way extinguish the right granted to Buyer hereunder which shall in such case continue to burden the LNG Plant.

29.6.5                   As used in this Article 29.6, the term “transfer” shall be defined to mean any transfer, sale, lease, or other conveyance, whether by agreement for sale or in any other manner except as otherwise provided in the first paragraph of this Article 29.6.  A sale of a parent company that holds an interest in NEWCO is not deemed to be a “transfer” provided that the value of the parent company’s interest in NEWCO is less than 25 per cent of the value of the parent company.

29.6.6                   Buyer shall have the right to record a memorandum of its right of First Refusal in the records of the county where the LNG Plant is located.

29.7                            Dispute Resolution Procedures .  In the event a dispute arises between the Parties related to this Sales Agreement, the following process shall be followed:

(a)                   Each Party will designate a senior executive (“Designated Representative”) to represent it in connection with any dispute that may arise between the Parties (a “Party Dispute”).  The Designated Representative shall initially be the persons identified in Article 25.1.  Subsequent changes in a Party’s Designated Representative shall be communicated according to Article 25.

(b)                  In the event that a Party Dispute should arise, the Designated Representatives will meet, with their attorneys, if they so agree, within five (5) Business Days after written request by any Party to any other Party (the “Dispute Notice”) in an effort to resolve the Party Dispute.

(c)                   If the Designated Representatives are unable to resolve the Party Dispute within twenty (20) Business Days following their first meeting, the Party Dispute will be submitted to non-binding mediation in Dallas, Texas before a mediator made available to the Parties through JAMS.

(d)                  In the event that the mediation process fails to result in a resolution of the Party Dispute within sixty (60) days following receipt of the Dispute Notice, the Parties may take any action they may deem necessary to protect their interests.

(e)                   The foregoing provisions of this Article 29.7 shall not be construed to prohibit any Party from commencing, at any time prior to the completion of the process described above,

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

 

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                                                any action or proceeding which such Party determines is necessary to protect or preserve any rights or remedies it may have in law or in equity.

ARTICLE 30 INTERPRETATION

30.1                            The captions in this Sales Agreement are for convenience of the Parties in identification of the provisions hereof and shall not constitute a part of the agreement nor be considered interpretive thereof. In the consideration and interpretation of this Sales Agreement, the following shall apply:

(a)                                   This Sales Agreement was prepared jointly by the Parties hereto and not by either Party to the exclusion of the other.

(b)                                  Failure to exercise any right or rights hereunder shall not be considered a waiver of such right or rights in the future.

ARTICLE 31 PRIOR AGREEMENTS

31.1                            This Sales Agreement contains the entire agreement of Buyer and Seller and supersedes all prior understandings or agreements whether oral or written between the Parties, with respect to the matters addressed herein.  This Sales Agreement shall be amended only by an instrument in writing signed by both parties hereto.

ARTICLE 32 TERMINATION

32.1                            In the event that Seller has not produced and delivered to Buyer 45,000 Gallons per day for a minimum of 25 consecutive days from the LNG Plant by December 1, 2009, Buyer may terminate this Sales Agreement upon 60 days written notice to Seller.

32.2                            In the event Seller is unable to complete and start up operations of the LNG Plant by December 1, 2009 due to unforeseen circumstances including but not limited to any legal actions, injunctions, or any governmental authorities, Seller may terminate this Sales Agreement upon 60 days written notice to Buyer.

32.3                            If either Party elects to terminate this Sale Agreement under Article 32.1 or 32.2, neither Party shall be liable to the other Party for any further obligations under this Sales Agreement.

32.4                            In the event Buyer wishes to terminate this Sales Agreement any time during the Term of this Sales Agreement and make a one time payment to Seller in lieu of continuing Take or Pay payments, Buyer may do so according to the following payment schedule. The one time payment will equal the applicable termination fee set forth below at the time of Seller’s receipt of Buyer’s written notice of its exercise of its termination right pursuant to this Article 32.4 in accordance with the table below.  Buyer will include specific details regarding the rational for Buyer’s decision to exercise this determination option.


Sales Agreement Year


Termination Fee

 

 

Effective Date through end of Year 1

[***]

Any time during year 2

[***]

Any time during year 3

[***]

Any time during year 4

[***]

Any time during year 5

[***]

Any time during year 6

[***]

Any time during year 7

[***]

Any time during year 8

[***]

Any time during year 9

[***]

Any time during year 10

[***]

 

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

 

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32.5                            In consideration of a payment made in accordance with the foregoing schedule, Seller agrees that without the prior written consent of Buyer, which consent may be withheld in the sole discretion of Buyer, Seller will not, prior to the tenth anniversary of the Effective Date (a) operate, or cause to be operated, the LNG Plant or sell, or cause to be sold, LNG produced by the LNG Plant or (b) sell or lease the LNG Plant to a third party, it being understood and agreed that by virtue of such payment Buyer has in effect paid for the shutdown of the LNG Plant for the remaining term of this Sales Agreement.  Seller may dismantle the LNG Plant and dispose of the components.  Until such time as the Plant may be dismantled and disposed of, Seller agrees to mothball the Plant until the tenth anniversary of the Effective Date of this Agreement, in a manner that it could be restarted to produce LNG in the event Buyer elects at a future date to purchase LNG from the Plant.  In the event Seller wishes to resume LNG production at the Ehrenberg location, Seller shall refund a portion of the Termination Fee which shall be calculated by multiplying the number of years remaining (including the year in which Seller resumes LNG production at the Ehrenberg location) before the tenth anniversary of the Effective Date by [***].  Seller shall have the right to move the Plant to a new location and resume LNG production.  If the LNG produced at the new location competes with Buyer’s operations, Seller shall refund a portion of the Termination Fee which shall be calculated by multiplying the number of years remaining (including the year in which Seller resumes LNG production at the new location) before the tenth anniversary of the Effective Date by [***].

ARTICLE 33 DAMAGES, FEES AND COSTS

33.1                            Except as otherwise expressly provided in this Sales Agreement, the Parties are entitled to recover as their sole and exclusive damages for breach of the price and quantity obligations under this Sales Agreement their actual damages resulting from such breach.

33.2                            In the event litigation is necessary to resolve a dispute, the prevailing Party shall be entitled to receive reimbursement by the other Party of its attorneys’ fees and costs of investigation and defense, and shall have the right to recover those fees and costs from the other Party.

ARTICLE 34 MUTUAL WAIVER OF CERTAIN REMEDIES

34.1                            EXCEPT AS TO THE PARTIES’ INDEMNIFICATION OBLIGATIONS WITH RESPECT TO THIRD PARTY CLAIMS SUBJECT TO SUCH OBLIGATIONS AND SUBJECT TO THE TAKE OR PAY OBLIGATIONS OF BUYER SET FORTH IN THIS SALES AGREEMENT, NEITHER PARTY SHALL BE LIABLE OR OTHERWISE RESPONSIBLE TO THE OTHER FOR CONSEQUENTIAL OR INCIDENTAL DAMAGES, FOR LOST PRODUCTION, OR FOR PUNITIVE DAMAGES AS TO ANY ACTION OR OMISSION, WHETHER CHARACTERIZED AS A SALES AGREEMENT BREACH OR TORT OR OTHERWISE, THAT ARISES OUT OF OR RELATES TO THIS SALES AGREEMENT OR ITS PERFORMANCE OR NONPERFORMANCE HEREUNDER.

ARTICLE 35 RELATIONSHIP OF THE PARTIES

35.1                            Seller is selling LNG to Buyer. By entering into this Sales Agreement, the Parties do not intend to create an agency, partnership, joint venture, or distributorship relationship.

ARTICLE 36 EXECUTION REQUIRED

36.1                            This Sales Agreement shall become effective only upon execution by both Parties hereto.

 

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

 

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ARTICLE 37 WAIVER OF RIGHT TO TRIAL BY JURY

EACH PARTY HERETO HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS SALES AGREEMENT OR ANY OTHER DOCUMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY OR THEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY).  EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PERSON HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PERSON WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS SALES AGREEMENT AND THE OTHER DOCUMENTS BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS ARTICLE.

 

 

[Signature page follows.]

 

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

 

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IN WITNESS WHEREOF, the Parties hereto have executed this LNG Sales Agreement as of the day and year first above written.

BUYER: