Table
of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
QUARTERLY REPORT
PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly
period ended September 30, 2008
Commission File
Number: 001-33480
CLEAN ENERGY FUELS
CORP.
(Exact name of registrant as specified in its charter)
Delaware
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33-0968580
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(State or other jurisdiction of
incorporation)
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(IRS Employer Identification No.)
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3020 Old Ranch
Parkway, Suite 200, Seal Beach CA 90740
(Address of principal executive offices, including zip
code)
(562) 493-2804
(Registrants 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, a non-accelerated filer, or a smaller reporting
company. See definitions of large accelerated filer, accelerated filer, and
smaller reporting company in Rule 12b-2 of the Exchange Act. (Check
one):
Large
accelerated filer
o
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Accelerated
filer
o
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Non-accelerated
filer
x
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Smaller
reporting company
o
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(Do
not check if a smaller reporting company)
|
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|
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 12, 2008, there were 50,195,471 shares of the
registrants common stock, par value $0.0001 per share, issued and outstanding.
Table of Contents
CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES
INDEX
Table of Con
tents
2
Table of Contents
PART I.
FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Clean Energy Fuels Corp. and Subsidiaries
Condensed Consolidated Balance Sheets
December 31, 2007 and September 30,
2008 (Unaudited)
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December 31,
2007
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September 30,
2008
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Assets
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Current assets:
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Cash and cash equivalents
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$
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67,937,602
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$
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30,392,856
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Restricted cash
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2,502,032
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Short-term investments
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12,479,684
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Accounts receivable, net of allowance for
doubtful accounts of $501,751 and $878,358 as of December 31, 2007 and
September 30, 2008, respectively
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11,026,890
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12,943,373
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Other receivables
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23,153,904
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11,793,587
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Inventory, net
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2,403,890
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2,460,328
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Deposits on LNG trucks
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15,515,927
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10,160,721
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Prepaid expenses and other current assets
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3,633,318
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4,946,082
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Total current assets
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136,151,215
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75,198,979
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Land, property and equipment, net
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88,676,318
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142,169,616
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Capital lease receivables
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763,500
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464,250
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Notes receivable and other long-term assets
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2,126,007
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5,266,654
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Investments in other entities
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385,806
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3,549,723
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Goodwill and other intangible assets
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20,922,098
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42,042,604
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Total assets
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$
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249,024,944
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$
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268,691,826
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Liabilities and Stockholders Equity
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Current liabilities:
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Current portion of long-term debt and
capital lease obligation
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$
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63,520
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$
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3,737,052
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Accounts payable
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10,547,451
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9,291,037
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Accrued liabilities
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5,381,541
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7,251,794
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Deferred revenue
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677,826
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717,169
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Total current liabilities
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16,670,338
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20,997,052
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Long-term debt and capital lease
obligation, less current portion
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161,377
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18,536,733
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Other long-term liabilities
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1,260,755
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1,240,665
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Total liabilities
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18,092,470
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40,774,450
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Commitments and contingencies
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Minority interest in subsidiary
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3,744,671
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Stockholders equity:
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Preferred stock, $0.0001 par value.
Authorized 1,000,000 shares; issued and outstanding no shares
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Common stock, $0.0001 par value. Authorized
99,000,000 shares; issued and outstanding 44,274,375 shares and
44,641,520 shares at December 31, 2007 and September 30, 2008,
respectively
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4,428
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4,463
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Additional paid-in capital
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297,866,745
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310,899,518
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Accumulated deficit
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(69,086,583
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)
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(87,565,158
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)
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Accumulated other comprehensive income
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2,147,884
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833,882
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Total stockholders equity
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230,932,474
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224,172,705
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Total liabilities and stockholders equity
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$
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249,024,944
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$
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268,691,826
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See accompanying notes to condensed
consolidated financial statements.
3
Table of Contents
Clean Energy Fuels Corp. and Subsidiaries
Condensed Consolidated Statements of
Operations
For the Three Months and Nine Months Ended
September 30, 2007 and 2008
(Unaudited)
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Three Months Ended
September 30,
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Nine Months Ended
September 30,
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2007
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2008
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2007
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2008
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Revenue
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$
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29,210,164
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$
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35,273,687
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$
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88,040,804
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$
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99,823,025
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Operating expenses:
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Cost of sales
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20,252,744
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26,111,054
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64,100,466
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77,138,760
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Derivative losses
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6,047,727
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340,746
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Selling, general and administrative
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9,528,605
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11,397,913
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26,269,201
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35,124,764
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Depreciation and amortization
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1,814,176
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2,310,527
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5,090,396
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6,557,967
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Total operating expenses
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31,595,525
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45,867,221
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95,460,063
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119,162,237
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Operating loss
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(2,385,361
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)
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(10,593,534
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)
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(7,419,259
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)
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(19,339,212
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)
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Interest income, net
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1,414,120
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78,399
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2,253,083
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1,182,962
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Other income (expense), net
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(50,000
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)
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(28,801
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)
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(229,177
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)
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11,177
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Equity in gains (losses) of equity method
investee
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19,881
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(120,441
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)
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Loss before income taxes
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(1,021,241
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)
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(10,524,055
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)
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(5,395,353
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)
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(18,265,514
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)
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Income tax expense
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(523,729
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)
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(99,171
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)
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(582,698
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)
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(199,141
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)
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Minority interest in net income
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(13,920
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)
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(13,920
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)
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Net loss
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$
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(1,544,970
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)
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$
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(10,637,146
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)
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$
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(5,978,051
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)
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$
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(18,478,575
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)
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Loss per share
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Basic
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$
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(0.03
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)
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$
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(0.24
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)
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$
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(0.15
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)
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$
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(0.42
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)
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Diluted
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$
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(0.03
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)
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$
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(0.24
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)
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$
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(0.15
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)
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$
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(0.42
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)
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Weighted average common shares outstanding
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Basic
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44,195,339
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44,330,818
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38,919,129
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44,304,636
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Diluted
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44,195,339
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44,330,818
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38,919,129
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44,304,636
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See accompanying notes to condensed
consolidated financial statements.
4
Table of Contents
Clean Energy Fuels Corp.
Condensed Consolidated Statements of Cash
Flows
For the Nine Months Ended September 30,
2007 and 2008
(Unaudited)
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Nine Months Ended
September 30,
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2007
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2008
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Cash flows from operating activities:
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Net loss
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$
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(5,978,051
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)
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$
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(18,478,575
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)
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Adjustments to reconcile net loss to net
cash provided by (used in) operating activities:
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Depreciation and amortization
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5,090,396
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6,557,967
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Provision for doubtful accounts
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1,179,600
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410,906
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Gain (loss) on disposal of assets
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178,674
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(9,555
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)
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Stock option expense
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5,425,443
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7,782,538
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Common stock issued in exchange for services
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22,500
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Minority interest in net income
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13,920
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Changes in operating assets and
liabilities, net of assets and liabilities acquired:
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Accounts and other receivables
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9,099,031
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9,989,396
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Inventory
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(1,221,776
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)
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(56,438
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)
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Deposits on LNG trucks
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(7,928,016
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)
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5,355,206
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Margin deposits on futures contracts
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(754,256
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)
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Capital lease receivables
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549,250
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299,250
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Prepaid expenses and other assets
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(1,508,219
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)
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(3,559,283
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)
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Accounts payable
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1,269,128
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(561,936
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)
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Accrued expenses and other
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2,479,123
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823,710
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Net cash provided by operating activities
|
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8,634,583
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7,835,350
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Cash flows from investing activities:
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|
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Purchases of property and equipment
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(29,874,682
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)
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(59,828,850
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)
|
Proceeds from sale of property and
equipment
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48,432
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Purchases of short-term investments
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(14,809,636
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)
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(45,230,061
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)
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Maturity or sales of short-term investments
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57,709,745
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Acquisition, net of cash acquired
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(19,615,122
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)
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Investments in other entities
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(377,855
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)
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(3,238,866
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)
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Restricted cash
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(2,502,032
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)
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Net cash used in investing activities
|
|
(45,062,173
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)
|
(72,656,754
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)
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Cash flows from financing activities:
|
|
|
|
|
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Proceeds from issuance of common stock and
exercise of stock options
|
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110,301,745
|
|
5,227,770
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|
Proceeds from long-term debt
|
|
|
|
22,124,120
|
|
Repayment of capital lease obligations and
long-term debt
|
|
(42,583
|
)
|
(75,232
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)
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Net cash provided by financing activities
|
|
110,259,162
|
|
27,276,658
|
|
|
|
|
|
|
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Net increase (decrease) in cash
|
|
73,831,572
|
|
(37,544,746
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)
|
Cash, beginning of period
|
|
937,445
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|
67,937,602
|
|
Cash, end of period
|
|
$
|
74,769,017
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$
|
30,392,856
|
|
|
|
|
|
|
|
Supplemental disclosure of cash flow
information
|
|
|
|
|
|
Income taxes paid
|
|
$
|
250
|
|
$
|
164,779
|
|
Interest paid
|
|
80,749
|
|
129,646
|
|
See accompanying notes to condensed
consolidated financial statements.
5
Table of Contents
CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 General
Nature of Business:
Clean
Energy Fuels Corp. (the Company) is engaged in the business of selling
natural gas fueling solutions to its customers primarily in the United States
and Canada. The Company has a broad customer base in a variety of markets
including public transit, refuse, airports and regional trucking. Clean Energy
operates or supplies approximately 175 natural gas fueling locations in
California, Texas, Colorado, Maryland, New York, New Mexico, Nevada,
Washington, Massachusetts, Georgia, Wyoming, Arizona, Ohio, and Alabama within
the United States, and in British Columbia and Ontario within Canada. The
Company also generates revenue through operation and maintenance agreements
with certain customers, through building and selling or leasing natural gas
fueling stations to its customers, and through financing its customers vehicle
purchases. In April 2008, the Company opened its first compressed natural
gas (CNG) station in Lima, Peru through the Companys joint venture, Clean
Energy del Peru. In August 2008,
the Company acquired 70% of the outstanding membership interests of Dallas
Clean Energy, LLC (DCE). DCE owns a facility that collects, processes and
sells landfill gas in Texas.
Basis of Presentation:
The
accompanying interim unaudited condensed consolidated financial statements
include the accounts of the Company and its subsidiaries, and, in the opinion
of management, reflect all adjustments, which include only normal recurring
adjustments, necessary to state fairly the Companys financial position,
results of operations and cash flows for the three and nine months ended September 30,
2007 and 2008. All intercompany accounts and transactions have been eliminated
in consolidation. The three and nine month periods ended September 30,
2007 and 2008 are not necessarily indicative of the results to be expected for
the year ending December 31, 2008 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, 2007 that are
included in the Companys Annual Report on Form 10-K filed with the SEC.
Reclassification:
A
reclassification has been made to the presentation of the statement of cash
flows for the nine months ended September 30, 2007 to conform to the
current year presentation. Deposits on liquified natural gas (LNG) trucks
have been reclassified from prepaid expenses and other assets to a separate
line item in the statement of cash flows for the nine months ended September 30,
2007.
Note 2
Acquisition
On
August 15, 2008, Clean Energy and Cambrian Energy McCommas Bluff LLC (Cambrian)
formed a joint venture to acquire all of the outstanding membership interests
of DCE. DCE owns a facility that collects, processes and sells landfill
gas at the McCommas Bluff landfill located in Dallas, Texas. This acquisition enables Clean Energy to
participate in the production of renewable biogas which may be used as a
vehicle fuel.
The
Company paid an aggregate of $19.1 million to acquire a 70% interest in
DCE. Of the purchase price, $1.0 million
was deposited into a third-party escrow as security for indemnification
claims. The amount remaining in the
escrow will be released to the sellers on August 15, 2009, except for
amounts subject to pending indemnification claims, if any.
The
Company borrowed $18.0 million from PlainsCapital Bank to finance its
acquisition of its membership interests in DCE. The Company also obtained
a $12.0 million line of credit from PlainsCapital Bank to finance capital
improvements of the DCE processing facility pursuant to a loan made by the
Company to DCE and to pay certain costs and expenses related to the acquisition
and the PlainsCapital Bank loan. As of September 30,
2008, the Company had borrowed $4.2 million under the line of credit (see note
11).
6
Table of Contents
The
Company accounted for the acquisition in accordance with SFAS No. 141,
Business Combinations.
The Company has completed a preliminary allocation of the purchase
price. Such allocation and amounts may
change as management finalizes its analyses.
The assets acquired and liabilities assumed were recorded at their
estimated fair values at the acquisition date. The following table summarizes
the preliminary allocation of the aggregate purchase price to the fair value of
the assets acquired and liabilities assumed, net of Cambrians minority
interest, in the DCE acquisition:
Current assets
|
|
$
|
1,129,389
|
|
Property, plant and equipment
|
|
1,821,770
|
|
Identifiable intangible assets
|
|
21,341,906
|
|
Total assets acquired
|
|
24,293,065
|
|
|
|
|
|
Current liabilities assumed
|
|
(1,480,770
|
)
|
Minority interest
|
|
(3,730,751
|
)
|
|
|
|
|
Total purchase price
|
|
$
|
19,081,544
|
|
Management
preliminarily allocated approximately $21.3 million to the identifiable
intangible asset related to the fair value of DCEs landfill lease with the
City of Dallas that was acquired with the acquisition. The fair value of the identifiable intangible
asset will be amortized on a straight-line basis over the remaining life of the
lease, approximately 16.5 years at the acquisition date.
The
results of DCEs operations have been included in the Companys consolidated
financial statements since August 15, 2008. The pro-forma effect of the acquisition is
not material to the Companys results of operations for the year ended December
31, 2007 and the first nine months of 2008.
Note 3
Cash and Cash Equivalents
The Company considers all highly liquid investments with maturities of
three months or less on the date of acquisition to be cash equivalents. 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 4
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 nine 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.
All of the short-term investments at December 31, 2007 matured or
were sold during the nine months ended September 30, 2008.
Note 5 Derivative Financial Instruments
The Company, in an effort to manage its natural gas commodity price
risk exposures related to certain contracts, utilizes derivative financial
instruments. The Company, from time to time, enters into natural gas futures
contracts that are over-the-counter swap transactions that convert its
index-based gas supply arrangements to fixed-price arrangements. The Company
accounts for its derivative instruments in accordance with SFAS No. 133,
Accounting for Derivative Instruments and Hedging
Activities
, as amended (SFAS 133). SFAS 133 requires the recognition of all
derivatives as either assets or liabilities in the consolidated balance sheet
and the measurement of those instruments at fair value. Historically, the Companys derivative
instruments have not qualified for hedge accounting under SFAS 133. The Company did not have any derivative
instruments during the year ended December 31, 2007, but had certain futures
contracts in place at September 30, 2008 to hedge a fixed-price LNG supply
contract with a customer. The futures contracts at September 30, 2008 are
being accounted for as cash flow hedges under SFAS 133 and are being used to
mitigate the Companys exposure to changes in the price of natural gas and not
for speculative purposes.
7
Table of Contents
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 consolidated statements of operations or in
accumulated other comprehensive income in the condensed consolidated balance
sheets in accordance with the provisions of SFAS 133.
For the three and nine month periods
ended September 30, 2008, the Company recorded losses of $6.0 million and
$0.3 million, respectively, related to its futures contracts in the
consolidated statements of operations.
These futures contracts were related to the portion of an LNG supply
contract that the Company bid on but was not awarded. The Company recorded unrealized losses of
$1.1 million in accumulated other comprehensive income for the three months
ended September 30, 2008 for the futures contracts applicable to the
portion of the LNG supply contract it was awarded (see note 6). The liability for these contracts is in
accrued liabilities on the Companys condensed consolidated balance sheet at September 30,
2008. There was no ineffectiveness of
the futures contracts recognized during the period. The Company recognized losses of $0.2 million
during the three and nine month periods ended September 30, 2008 related
to futures contracts applicable to this supply contract. Such amounts are included in cost of sales in
the condensed consolidated statements of operations.
The Company is required to make certain deposits on its futures
contracts, should any exist. At September 30, 2008, the Company had $0.8
million of margin deposits related to its futures contracts, all of which was
classified as current as of September 30, 2008.
Note 6 Fixed Price and Price Cap Sales Contracts
The Company enters into contracts with various customers, primarily
municipalities, to sell LNG or CNG at fixed prices or at prices subject to a
price cap. The contracts generally range
from two to five years. The most significant cost component of LNG and CNG is
the price of natural gas.
As part of determining the fixed price or price cap in the contracts,
the Company works with its customers to determine their future usage over the
contract term. However, the Companys 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 Companys 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 customers 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 5) 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 Companys 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 Companys 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 Companys statements of operations during this
historical period of rising natural gas prices for the future commitments under
these contracts. As a result, the Companys 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).
8
Table of Contents
The following table summarizes important information regarding the
Companys fixed price and price cap supply contracts under which it is required
to sell fuel to its customers as of September 30, 2008:
|
|
Estimated
volumes (a)
|
|
Average
price (b)
|
|
Contracts
duration
|
|
CNG fixed price contracts
|
|
1,207,617
|
|
$
|
1.17
|
|
through 12/13
|
|
LNG fixed price contracts
|
|
2,536,371
|
|
$
|
0.51
|
|
through 07/09
|
|
CNG price cap contracts
|
|
2,253,804
|
|
$
|
0.83
|
|
through 12/09
|
|
LNG price cap contracts
|
|
1,050,000
|
|
$
|
0.62
|
|
through 03/09
|
|
This table does not include two 2.1 million LNG gallon per year renewal
options beginning April 1, 2009 that one of our customers possesses
related to an LNG price cap contract.
The contract contains a price cap of $7.50 per MMbtu on the SoCal Border
Index.
(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 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 in
the customers contract.
At September 30, 2008, we estimate we will incur between $0.4
million and $0.5 million to cover the increased price of natural gas above
the inherent price of natural gas embedded in our customers fixed price and
price cap contracts over the duration of the contracts. These estimates were
based on natural gas futures prices on September 30, 2008, and these
estimates may change based on future natural gas prices and may be
significantly higher or lower. Our estimated volumes under these contracts, in
gasoline gallon equivalents, expire as follows:
October 1, 2008 through December 31,
2008
|
|
2,062,785
|
|
2009
|
|
2,831,296
|
|
2010
|
|
230,000
|
|
2011
|
|
230,000
|
|
2012
|
|
230,000
|
|
2013
|
|
230,000
|
|
This table does not include the two 2.1 million LNG gallon per year
renewal options that one of our customer possesses related to an LNG price cap
contract.
On April 18, 2008, the Company purchased certain natural gas
futures contracts to attempt to economically hedge the Companys exposure to
cash flow variability related to the commodity component of an LNG supply
contract for which the Company had submitted a fixed-price bid. As previously disclosed in the Companys Form 8-K
dated June 19, 2008, the supply contract for which the futures contracts
were purchased was awarded to a competitor of the Company. The Company protested the award of the
contract to its competitor and ultimately the Company was awarded a portion of
the contract representing approximately one-third of the contract volumes. In July 2008, the Company then sold the
futures contracts related to the portion of the contract it was not
awarded. Due to the decrease in the
price of natural gas between the date the futures contracts were purchased and
the date they were sold, the Company ultimately realized a net loss of $0.3
million related to the sale of the futures contracts purchased with respect to
the portion of the fixed-price contract that was not awarded to the
Company. The remaining futures contracts
qualify for hedge accounting as cash flow hedges under SFAS 133 (see note 5).
9
Table of Contents
Note 7 Other Receivables
Other receivables at December 31, 2007 and September 30, 2008
consisted of the following:
|
|
December 31,
2007
|
|
September 30,
2008
|
|
|
|
|
|
|
|
Loans to customers to finance vehicle
purchases
|
|
$
|
1,393,549
|
|
$
|
1,906,777
|
|
Advances to vehicle manufacturers
|
|
4,871,373
|
|
2,903,707
|
|
Fuel tax credits
|
|
14,920,145
|
|
5,532,061
|
|
Other
|
|
1,968,837
|
|
1,451,042
|
|
|
|
$
|
23,153,904
|
|
$
|
11,793,587
|
|
Note 8 Land, Property and Equipment
Land, property and equipment at December 31,
2007 and September 30, 2008 are summarized as follows:
|
|
December 31,
2007
|
|
September 30,
2008
|
|
Land
|
|
$
|
472,616
|
|
$
|
472,616
|
|
LNG liquefaction plant
|
|
12,898,178
|
|
12,921,046
|
|
Station equipment
|
|
48,318,709
|
|
52,442,945
|
|
LNG tanker trailers
|
|
11,698,145
|
|
11,793,681
|
|
Other equipment
|
|
6,937,083
|
|
10,524,396
|
|
Construction in progress
|
|
32,297,191
|
|
84,066,532
|
|
|
|
112,621,922
|
|
172,221,216
|
|
Less accumulated depreciation
|
|
(23,945,604
|
)
|
(30,051,600
|
)
|
|
|
$
|
88,676,318
|
|
$
|
142,169,616
|
|
Note 9 Investments in Other Entities
In
August 2008, the Company invested approximately $3.2 million in The
Vehicle Production Group LLC (VPG), a company that is developing a natural
gas vehicle made in the United States for taxi and paratransit use. The Company
committed to fund up to $10 million in VPG from August 2008 through March 2010. $7.5 million is a firm commitment by the
Company, and $2.5 million is contingent on VPG not being able to raise money on
more-favorable terms than the funding from the original investor group.
The Company accounts for its
investment in VPG under the cost method of accounting as the Company does not
have the ability to exercise significant influence over VPGs operations.
On August 27, 2008, a subsidiary of the Company converted outstanding
commercial loans previously made to Bachman NGV, Inc. (BAF), a natural gas
vehicle conversion company, into a secured convertible promissory note (the Note)
that is convertible into equity interests in BAF. The
Note is convertible at the Companys option after August 27, 2009 and may be
converted earlier upon an acquisition of BAF.
As of September 30, 2008, the $3.6 million outstanding under the Note would
convert into approximately 47% of the outstanding equity interests of BAF if
fully converted. The Company may, at the Companys discretion, advance up to
$2.4 million in additional funds to BAF under the Note. The Note bears interest
at 5% per annum and is due August 30, 2010.
Note 10 Accrued Liabilities
Accrued liabilities at December 31, 2007 and September 30,
2008 consisted of the following:
|
|
December 31,
2007
|
|
September 30,
2008
|
|
Salaries and wages
|
|
$
|
1,495,196
|
|
$
|
1,008,327
|
|
Accrued gas purchases
|
|
1,840,358
|
|
1,820,241
|
|
Obligation under derivative liability
|
|
|
|
1,065,797
|
|
Accrued employee benefits
|
|
317,798
|
|
804,953
|
|
Other
|
|
1,728,189
|
|
2,552,476
|
|
|
|
$
|
5,381,541
|
|
$
|
7,251,794
|
|
10
Table of Contents
Note 11 Long-term Debt
In conjunction with the Companys acquisition of its 70% interest in
DCE (see note 2), on August 15, 2008, the Company entered into a Credit
Agreement with PlainsCapital Bank. The
Company borrowed $18.0 million (the Facility A Loan) to finance the
acquisition of its membership interests in DCE
.
The
Company also obtained a $12.0 million line of credit from PlainsCapital Bank to
finance capital improvements of the DCE processing facility and to pay certain
costs and expenses related to the acquisition and the PlainsCapital Bank loans (the
Facility B Loan). As of September 30,
2008, the Company had borrowed $4.2 million under the Facility B Loan. The Company may request funds up to $12.0
million under the Facility B Loan through February 15, 2009. Interest accrues daily on the Facility A
and B Loans at the greater of the prime rate of interest for the United States
plus 0.50% per annum or 5.50% per annum. The
Company paid a facility fee of $300,000 in connection with the Credit
Agreement. As of September 30,
2008, the unamortized balance of the facility fee was $292,500. Amortization of the facility fee is recorded
as additional interest expense in the consolidated statements of operations.
The Facility A Loan is due in level payments of principal and
interest based on a 14 year amortization period. Payments of principal and
interest are due on the 15th of each month until August 15, 2013, at which
time the remaining amount of the unpaid principal and interest on the
Facility A Loan is due and payable.
Interest on the unpaid principal balance of the Facility B Loans is due
and payable quarterly commencing on September 30, 2008. The principal amount of the Facility B
Loans is due and payable in annual payments commencing on August 1, 2009,
and continuing each anniversary date thereafter, with each such payment being
in an amount equal to the lesser of the aggregate principal amount of the
Facility B Loan then outstanding or $2,800,000.
On August 15, 2013, the remaining amount of unpaid principal and
interest under the Facility B Loans is due and payable.
The Credit Agreement requires the Company to comply with certain
covenants. The Company may not incur
indebtedness or liens except as permitted by the Credit Agreement, or declare
or pay dividends. The Company must
maintain minimum liquidity of not less than $6.0 million at each quarter end
beginning December 31, 2008, maintain an accounts receivable balance, as
defined, at each month end of not less than $10.0 million beginning August 31,
2008, maintain consolidated net worth, as defined, of not less than $150.0
million and a debt to equity ratio, as defined, of not more than 0.3 to 1 at
each quarter end beginning September 30, 2008, and a debt service ratio,
as defined, of not less than 1.5 to 1 for each quarterly period beginning June 30,
2009. If the Company defaults on the
Credit Agreement, all of the obligations under the Credit Agreement will become
immediately due and payable.
The Credit Agreement is secured by the Companys interest in, and note
receivable from, DCE (described below), certain of the Companys accounts
receivable and inventory balances and 45 of the Companys LNG tanker trailers.
As part of the transaction, the Company also entered into a Loan
Agreement with DCE (the DCE Loan) to provide secured financing of up to $14.0
million to DCE for future capital expenditures.
Upon closing of the acquisition of DCE, the Company funded approximately
$714,000 under the agreement. The funds
were obtained as part of the initial $4.2 million funded under the Facility B
Loan with PlainsCapital Bank to the Company.
Interest on the unpaid balance accrues at a rate of 12% per annum and is
payable quarterly beginning September 30, 2008. The principal amount of the loan is due and
payable in annual payments commencing on August 1, 2009, and continuing
each anniversary date thereafter, with each such payment being in an amount equal
to the lesser of the aggregate principal amount of the DCE Loan then
outstanding or $2,800,000. On August 1,
2013, the entire amount of unpaid principal and interest under the DCE Loan is
due and payable. The principal and accrued
interest balances as well as any interest income related to the DCE Loan are
eliminated in the consolidated financial statements of the Company. Any event of default by DCE on the DCE Loan
results in a cross-default of the Companys Credit Agreement with PlainsCapital
Bank. Events of default include failure
to make payments when due, DCEs failure to perform under the provisions of its
landfill lease with the City of Dallas, DCEs violation of a covenant under its
operating agreement and other standard events of default.
Also as part of the transaction, the Company granted DCEs minority
investor an exclusive, non-assignable option to purchase from the Company up to
and including a 19% membership interest in DCE.
The exercise price of the option is $368,000 for each 1%, up to
$6,992,000 for the total 19%. The option
may be exercised in whole or in part (but only in 1% increments) during the
ten-year period commencing on the date which the DCE Loan has been repaid in
full.
11
Table of Contents
Principal
payments under long-term debt and capital lease obligations for the annual
periods ending September 30, are as follows:
|
|
Facility A Loan
|
|
Facility B Loan
|
|
Capital Lease
|
|
Total
|
|
2009
|
|
$
|
868,607
|
|
$
|
2,800,000
|
|
$
|
68,445
|
|
$
|
3,737,052
|
|
2010
|
|
918,301
|
|
1,364,549
|
|
75,613
|
|
2,358,463
|
|
2011
|
|
970,838
|
|
|
|
33,797
|
|
1,004,635
|
|
2012
|
|
1,024,062
|
|
|
|
|
|
1,024,062
|
|
2013
|
|
14,149,573
|
|
|
|
|
|
14,149,573
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
17,931,381
|
|
$
|
4,164,549
|
|
$
|
177,855
|
|
$
|
22,273,785
|
|
Note 12 Issuance of Common Stock
On September 24, 2008, the Company entered into a subscription
agreement with Boone Pickens Interests, Ltd. pursuant to which the Company
issued and sold a total of 319,488 shares of its common stock at a purchase
price of $15.65 per share, the closing price of its common stock on the Nasdaq
Global Market, for an aggregate purchase price of approximately $5.0
million. Boone Pickens Interests, Ltd.
is a limited partnership, the limited partner interest in which is owned
collectively by certain trusts. Boone Pickens, a director of the Company and
the Companys largest stockholder, is the settlor of such trusts.
Note 13 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,
|
|
|
|
2007
|
|
2008
|
|
2007
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted:
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares
outstanding
|
|
44,195,339
|
|
44,330,818
|
|
38,919,129
|
|
44,304,636
|
|
Certain securities were excluded from the diluted earnings per share
calculations at September 30, 2007 and 2008, respectively, as the
inclusion of the securities would be anti-dilutive to the calculation. The
amounts outstanding as of September 30, 2007 and 2008 for these
instruments are as follows:
|
|
September 30,
|
|
|
|
2007
|
|
2008
|
|
|
|
|
|
|
|
Options
|
|
5,720,666
|
|
7,018,955
|
|
Warrants
|
|
15,000,000
|
|
15,000,000
|
|
Note 14 Comprehensive Income (Loss)
The following
table presents the Companys comprehensive loss for the nine months ended September 30,
2007 and 2008:
|
|
Nine Months Ended
September 30,
|
|
|
|
2007
|
|
2008
|
|
Net loss
|
|
$
|
(5,978,051
|
)
|
$
|
(18,478,575
|
)
|
Derivative unrealized losses
|
|
|
|
(1,065,797
|
)
|
Foreign currency translation adjustments
|
|
663,665
|
|
(248,205
|
)
|
|
|
|
|
|
|
Comprehensive loss
|
|
$
|
(5,314,386
|
)
|
$
|
(19,792,577
|
)
|
12
Table of Contents
Note 15 Stock-Based Compensation
The following table summarizes the compensation expense and related
income tax benefit related to stock
-
based
compensation expense recognized during the periods:
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
|
|
2007
|
|
2008
|
|
2007
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
Stock options:
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense
|
|
$
|
1,592,789
|
|
$
|
2,684,207
|
|
$
|
5,425,443
|
|
$
|
7,782,538
|
|
Income tax benefit
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense, net of
tax
|
|
$
|
1,592,789
|
|
$
|
2,684,207
|
|
$
|
5,425,443
|
|
$
|
7,782,538
|
|
Stock Options
The
following table summarizes all stock option activity during the nine months
ended September 30, 2008:
|
|
Number
of
Shares
|
|
Weighted-
Average
Exercise
Price
|
|
|
|
|
|
|
|
Outstanding at December 31, 2007
|
|
6,553,036
|
|
$
|
9.37
|
|
Granted
|
|
616,000
|
|
15.86
|
|
Exercised
|
|
(45,914
|
)
|
4.96
|
|
Cancelled/Forfeited
|
|
(104,167
|
)
|
13.97
|
|
Outstanding at September 30, 2008
|
|
7,018,955
|
|
9.88
|
|
|
|
|
|
|
|
Exercisable at September 30, 2008
|
|
3,375,787
|
|
5.93
|
|
|
|
|
|
|
|
|
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 2008:
|
|
Nine months
Ended
September 30,
2008
|
|
|
|
|
|
Dividend yield
|
|
0.00
|
%
|
Expected volatility
|
|
54.67
|
%
|
Risk-free interest rate
|
|
2.93
|
%
|
Expected life in years
|
|
6.00
|
|
Based on these assumptions, the weighted average grant date fair value
of options granted during the nine months ended September 30, 2008 was
$8.57.
Note 16 Use of Estimates
The preparation of consolidated financial statements in conformity with
U.S. generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and the disclosure of contingent assets and liabilities at the date
of the consolidated financial statements and revenues and expenses during the
reporting period. Actual results could differ from those estimates.
13
Table of Contents
Note 17 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 Companys 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 Companys 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
Companys consolidated financial position, results of operations, or liquidity.
As of September 30, 2008, the Company has remaining contractual
commitments related to constructing its LNG liquefaction plant in California of
$9.9 million.
Note 18 Income Taxes
FASB Interpretation No. 48, Accounting for Uncertainty in Income
Taxes, an interpretation of FASB Statement No. 109 (FIN 48), requires
that the Company recognize the impact of a tax position in its financial
statements if the position is more likely than not of being sustained by the
taxing authority upon examination, based on the technical merits of the
position.
FIN 48 requires the Company to accrue
interest based on the difference between the tax position recognized in the
financial statements and the amount claimed on the return. The net interest incurred was
immaterial for the nine months ended September 30, 2007 and 2008. FIN 48 further requires that penalties be
accrued if the tax position does not meet the minimum statutory threshold to
avoid penalties. No penalties have been
accrued by the Company. The Companys
unrecognized tax benefits as of September 30, 2008 are unchanged from December 31,
2007.
Income
tax returns are subject to audit by federal, state and local governments,
sometimes several years after a return is filed. The Company is currently under audit by the
Internal Revenue Service for tax years 2005 through 2007 and the State of
California for tax years 2004 and 2005.
Disputes may arise during the course of such audits as to facts and
different interpretations of tax law.
Note 19 Recently Adopted Accounting Changes
On January 1, 2008, the Company adopted the applicable provisions
of SFAS No. 157,
Fair Value Measurements
(SFAS
157), which defines fair value, establishes a framework for measuring fair
value and enhances disclosures about fair value measurements related to
financial instruments. In December 2007, the FASB provided a one-year
deferral of SFAS 157 for non-financial assets and non-financial liabilities,
except those that are recognized or disclosed at fair value on a recurring
basis, at least annually. Accordingly, the Companys adoption of SFAS 157 was
limited to financial assets and liabilities.
During the nine months ended September 30, 2008, the Companys
financial instruments have consisted of short-term investments and natural gas
futures contracts. The Company uses quoted market prices to measure fair value
of its short-term investments. The
Company uses quoted forward price curves, discounted to reflect the time value
of money, to value its natural gas futures contracts. At September 30, 2008, the Company did
not have any short-term investments and its futures contracts qualified for
hedge accounting under SFAS No. 133 and are recorded in accumulated other
comprehensive income in the accompanying condensed consolidated balance sheet.
SFAS 157 includes a fair value hierarchy that is intended to increase
consistency and comparability in fair value measurements and related
disclosures. The fair value hierarchy is based on inputs to valuation
techniques that are used to measure fair value that are either observable or
unobservable. Observable inputs reflect assumptions market participants would
use in pricing an asset or liability based on market data obtained from
independent sources while unobservable inputs reflect a reporting entitys
pricing based upon their own market assumptions. SFAS 157 establishes a
three-tiered fair value hierarchy which prioritizes the inputs used in
measuring fair value as follows:
·
Level 1.
Observable inputs such as quoted prices
in active markets;
14
Table of Contents
·
Level 2.
Inputs, other than quoted prices, that
are observable for the asset or liability, either directly or indirectly. These
include quoted prices for similar assets or liabilities in active markets and
quoted prices for identical or similar assets or liabilities in markets that
are not active; and
·
Level 3.
Unobservable inputs in which there is
little or no market data, which require the reporting entity to develop its own
assumptions.
The following table reflects the fair value as defined by SFAS 157, of
the Companys natural gas futures contracts:
|
|
Balance at
September 30,
2008
|
|
Quoted Prices
In Active Markets
for Identical Items
(Level 1)
|
|
Significant Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Natural gas futures contracts obligation
|
|
$
|
1,065,797
|
|
$
|
|
|
$
|
1,065,797
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 20 Subsequent Events
Termination
of FuelMaker Acquisition
On September 5, 2008, the
Company entered into a Share Purchase Agreement with American Honda Motor Co., Inc.
(Honda), John G. Armstrong (as sole trustee of The FuelMaker Trust) and
FuelMaker Corporation, pursuant to which the Company agreed to purchase
FuelMaker Corporation for $17 million in cash. Under the terms of the
purchase agreement, either the Company or Honda had the right to terminate the
purchase agreement, without any obligation or liability thereunder, if the
closing did not occur on or before October 3, 2008.
The closing did
not occur by October 3, 2008 primarily due to the fact that the sellers
(Honda and FuelMaker) were unable to deliver audited financial statements by October 3,
2008 for FuelMaker Corporations parent company, a subsidiary of Honda, which
financial statements were required to be prepared in accordance with Canadian
generally accepted accounting principles and reconciled to U.S. generally
accepted accounting principles. The Company continued negotiations with
Honda after October 3, 2008 to extend the Share Purchase Agreement on
revised terms.
On October 13,
2008, Honda delivered to the Company a notice that it intended to terminate the
purchase agreement; and, after subsequent discussions, on October 15,
2008, the Company and Honda mutually agreed to terminate the purchase agreement
in accordance with its terms. The
Company expects to record expenses of between $0.6 million and $0.8 million in
the fourth quarter of 2008 for costs associated with the transaction.
There are no termination fees or other significant liabilities associated with
the termination of the Share Purchase Agreement.
Issuance
of Common Stock and Warrants
On October 28, 2008, the
Company entered into a Placement Agent Agreement (the Placement Agent Agreement) relating to
the sale and issuance by the Company to select investors of up to 4,419,192
units (the Units),
with each Unit consisting of (i) one share of the Companys common stock,
par value $0.0001 per share, (ii) a warrant to purchase 0.75 shares of
Common Stock (the Series I Warrant), and (iii) one warrant to purchase
up to 0.2571 shares of Common Stock (the Series II Warrant). The price of
each Unit was $7.92 per Unit. The transaction closed on November 3, 2008 and
the Company issued 4,419,192 shares of common stock, Series I Warrants to
purchase up to 3,314,394 shares of Common Stock, and Series II Warrants to
purchase up to 1,136,364 shares of Common Stock. The Company received approximately
$32.5 million after deducting the placement agents fees and other offering
expenses.
The Series I
Warrants are exercisable beginning six months from the date of issuance for a
period of seven years from the date they become exercisable, and carry an
exercise price of $13.50 per share. On the first anniversary of the issuance of
the Series I warrants, the exercise price will reset to an exercise price
equal to one-hundred twenty percent (120%) of the closing price of the Companys
common stock on such first anniversary date. On the second anniversary of
the issuance of the Series I warrants, the exercise price will reset to an
exercise price equal to one-hundred twenty percent (120%) of the closing price
of the Companys common stock on such second anniversary date. However,
under the terms of the Series I warrants, no such reset adjustment will
operate to increase the exercise price above the then current exercise price at
the time of the first or second anniversary of the issuance of the Series I
warrant.
The Series II
Warrants became exercisable on November 5, 2008 upon the failure of the
California Alternative Fuel Vehicles and Renewable Energy Act, or Proposition
10, in the California statewide election. The Series II Warrants have all been
exercised on a cashless basis at the exercise price of $0.01 per share, which
resulted in the issuance of 1,134,759 shares of common stock to the Series II
Warrant holders on November 12, 2008.
15
Table of Contents
Item 2. Managements Discussion a
nd 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, but their absence does not mean that a statement is not
forward-looking. 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 primarily in the
United States and Canada. In April 2008,
we opened our first CNG station in Lima, Peru, through our joint venture, Clean
Energy del Peru. Our primary business
activity is selling 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. In August 2008,
we acquired 70% of the outstanding membership interest of Dallas Clean Energy,
LLC (DCE). DCE owns a facility that
collects, processes and sells landfill gas at the McCommas Bluff landfill
located in Dallas, Texas.
Overview
This overview discusses matters on which our
management primarily focuses in evaluating our financial condition and
operating performance.
Sources of revenue
. We generate the vast majority of our revenue
from selling 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, financing our customers natural
gas vehicle purchases and selling landfill gas through our interest in DCE.
Key operating data
. In evaluating our operating performance, our
management focuses primarily on (1) the amount of CNG and LNG gasoline
gallon equivalents delivered (which we define as (i) the volume of gasoline
gallon equivalents we sell to our customers, plus (ii) the volume of gasoline
gallon equivalents dispensed to our customers at stations where we provide
O&M services but do not directly sell the CNG or LNG, plus (iii) our
proportionate share of the gasoline gallon equivalents sold through our joint
venture in Peru and our interest in the McCommas Bluff Landfill in Dallas,
Texas), and (2) our revenue and net income (loss). The following table,
which you should read in conjunction with our condensed consolidated financial
statements and notes contained elsewhere in this report, presents our key
operating data for the years ended December 31, 2005, 2006 and 2007 and
for the three and nine months ended September 30, 2007 and 2008:
16
Table of Contents
Gasoline gallon equivalents
delivered (in millions)
|
|
Year Ended
December 31,
2005
|
|
Year Ended
December 31,
2006
|
|
Year Ended
December 31,
2007
|
|
Three Months
Ended
September 30,
2007
|
|
Nine Months
Ended
September 30,
2007
|
|
Three Months
Ended
September 30,
2008
|
|
Nine Months
Ended
September 30,
2008
|
|
CNG
|
|
36.1
|
|
41.9
|
|
48.0
|
|
12.9
|
|
36.3
|
|
12.9
|
|
36.3
|
|
LNG
|
|
20.7
|
|
26.5
|
|
27.3
|
|
7.1
|
|
20.8
|
|
5.8
|
|
18.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
56.8
|
|
68.4
|
|
75.3
|
|
20.0
|
|
57.1
|
|
18.7
|
|
54.8
|
|
Operating data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
77,955,083
|
|
$
|
91,547,316
|
|
$
|
117,716,233
|
|
$
|
29,210,164
|
|
$
|
88,040,804
|
|
$
|
35,273,687
|
|
$
|
99,823,025
|
|
Net income (loss)
|
|
17,257,587
|
|
(77,500,741
|
)
|
(8,894,362
|
)
|
(1,544,970
|
)
|
(5,978,051
|
)
|
(10,637,146
|
)
|
(18,478,575
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Key trends in 2005, 2006, and 2007
. Vehicle fleet demand for natural gas fuels
increased during the three years ended December 31, 2005, 2006 and 2007.
We believe this growth in demand was attributable primarily to the rising prices
of gasoline and diesel relative to CNG and LNG during these periods and
increasingly stringent environmental regulations affecting vehicle fleets. We
capitalized on this growing demand by securing new fleet customers in a variety
of markets, including public transit, refuse hauling, airports, taxis and
regional trucking.
The number of fueling stations we served grew from 147 at December 31,
2004 to 175 at September 30, 2008 (a 19.0% increase). The amount of CNG and LNG
gasoline gallon equivalents we delivered from 2005 to 2007 increased by 32.6%.
Our cost of sales also increased during these periods, which was attributable
primarily to the increased price of natural gas and increased costs related to
delivering CNG and LNG to our customers.
Recent developments
.
On September 5, 2008, we entered into a Share Purchase Agreement with
American Honda Motor Co., Inc. (Honda), John G. Armstrong (as sole
trustee of The FuelMaker Trust) and FuelMaker Corporation, pursuant to which we
agreed to purchase FuelMaker Corporation for $17 million in cash. Under the terms of the purchase agreement,
either we or Honda had the right to terminate the purchase agreement, without
any obligation or liability thereunder, if the closing did not occur on or
before October 3, 2008. On October 13,
2008, Honda delivered to us a notice that it intended to terminate the purchase
agreement; and, after subsequent discussions, on October 15, 2008, we and
Honda mutually agreed to terminate the purchase agreement in accordance with
its terms. On November 3, 2008, we
completed a sale of 4,419,192 units of common stock and warrants for $7.92 per
unit (See note 20 to the accompanying condensed consolidated financial
statements for a discussion of the transaction) and raised net proceeds of
approximately $32.5 million after deducting offering costs.
In October and November of 2008, we spent approximately
$15 million supporting Proposition 10, the California Alternative Fuel Vehicles
and Renewable Energy Initiative.
California voters failed to pass Proposition 10 in the November 4, 2008
election. The $15 million we spent
supporting Proposition 10 in October and November 2008 will be reflected in
selling, general and administrative expense in our financial statements for the
fourth quarter of 2008.
Anticipated future trends
.
We anticipate that, over the long term, the prices for gasoline and diesel will
continue to be higher than the price of natural gas as a vehicle fuel, and more
stringent emissions requirements will continue to make natural gas vehicles an
attractive alternative to traditional gasoline and diesel powered vehicles. We
believe there will be significant growth in the consumption of natural gas as a
vehicle fuel among vehicle fleets, and our goal is to capitalize on this trend
and enhance our leadership position as this market expands. We have built a
natural gas fueling station, and plan to build additional natural gas fueling
stations, that will provide LNG to fleet vehicles at the Ports of Los Angeles
and Long Beach. We also anticipate expanding our sales of CNG and LNG in the
other markets in which we operate, including public transit, refuse hauling and
airports. Consistent with the anticipated growth of our business, we also
expect that our operating costs and capital expenditures will increase,
primarily from the logistics of delivering more CNG and LNG to our customers,
as well as from the anticipated expansion of our station network. We also
continue to incur significant costs related to the LNG liquefaction plant we are
in the process of building in California. Additionally, we have and will
continue to increase our sales and marketing team and other necessary personnel
as we seek to expand our existing markets and enter new markets, which will
also result in increased costs.
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. On September 24, 2008, we sold 319,488
shares of our common stock at a purchase price of $15.65 per
share to Boone Pickens Interests, Ltd. for proceeds of approximately $5.0
million. On November 3, 2008 we sold
4,419,192 shares of common stock and warrants exercisable for common stock and
received net proceeds of approximately $32.5 million. (See note 20 to the accompanying condensed
consolidated financial statements for a discussion of the transaction). After this transaction, we had approximately
$38.5 million in total cash and cash equivalents.
17
Table
of Contents
Our business plan for the last three months of 2008 calls for
approximately $23.0 million in capital expenditures (primarily related to
building our LNG liquefaction plant in California and constructing new fueling
stations) and $0.8 million for financing natural gas vehicle purchases by our
customers. We may also seek to acquire
companies or assets in the natural gas fueling infrastructure, services and
production industries. If we do so, we
may need to raise additional capital as necessary to fund any such
acquisitions, which are not budgeted for in our 2008 business plan. We anticipate that we will need to
raise additional capital in 2009 to fund our 2009 capital expenditures program;
however, the timing and necessity of any future capital raise will depend primarily
on our rate of new station construction and other capital expenditures.
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 condensed consolidated financial statements,
have materially impacted our results of operations in recent periods. For the
years ended December 31, 2005, 2006 and 2007, derivative (gains) losses
were $(44,067,744), $78,994,947, and $0, respectively. For the nine months
ended September 30, 2007 and 2008, derivative (gains) losses were $0 and
$340,746, respectively. For this reason and others, we caution investors that
our past operating results may not be indicative of future results. For more
information, please read Volatility of Earnings and Cash Flows and Risk
Management Activities below.
Business risks and uncertainties
.
Our business and prospects are exposed to numerous risks and uncertainties. For
more information, see Risk Factors in Part II, Item 1A of this report.
Operations
We generate revenues principally by selling CNG and LNG to our vehicle
fleet customers. For the nine months ended September 30, 2008, CNG
represented 66% and LNG represented 34% 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 and selling landfill gas provided by our interest in DCE (commencing
in August 2008). 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 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. Effective January 1,
2007, 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. We will continue to offer fixed price
contracts as appropriate and consistent with our revised natural gas hedging
policy revised in May 2008. Our
fleet customers typically are billed monthly based on the volume of CNG sold at
a station. The remainder of our CNG sales are on a per fill-up basis at prices
we set at the pump based on prevailing market conditions. These customers
typically pay using a credit card at the station. In April 2008, we opened our first CNG
station in Lima, Peru through our joint venture Clean Energy del Peru.
LNG Sales
We sell substantially all of our LNG to fleet customers, who typically
own and operate their fueling stations. We also sell a small volume of LNG to
customers for non-vehicle use. We procure LNG from third-party producers and
also produce LNG at our liquefaction 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 prior to December 31, 2006. Effective January 1, 2007, 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
18
Table of Contents
entered into before January 1, 2007, including two one-year
renewal periods beginning April 1, 2009 that one of our customers is
entitled to should they choose to exercise such renewals. The renewal periods, if exercised, would
obligate us to sell the customer approximately 2.1 million LNG gallons on an
annual basis subject to a price cap of $7.50 per MMbtu on the SoCal Border index
for each renewal year. We will continue
to offer fixed price contracts as appropriate and consistent with our revised natural
gas hedging policy adopted in May 2008.
Our LNG contracts provide that we charge our customers periodically
based on the volume of LNG supplied.
Government Incentives
From October 1, 2006 through December 31, 2009, we may
receive a 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.
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. 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 or pay deposits with respect to such
vehicles prior to receiving a firm order from our customers, which we may be
required to purchase if our customer fails to purchase the vehicle as anticipated.
As of September 30, 2008, we have not generated significant revenue from
vehicle finance activities.
Landfill Gas
In August 2008, we acquired 70% of the outstanding membership
interests of DCE. DCE owns a facility
that collects, processes and sells landfill gas at the McCommas Bluff landfill
located in Dallas, Texas. A small
portion of our revenues are derived from our interest in DCE.
Volatility of Earnings and Cash Flows
Our earnings and cash flows historically have fluctuated significantly
from period to period based on our futures activities, as all but a few of our
futures contracts have not historically qualified for hedge accounting under
SFAS 133. See Critical Accounting Policies 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 and $5.7 million for the
three months ended September 30, 2005 and June 30, 2008, and
derivative losses of $19.9 million, $0.3 million, $65.0 million,
$13.7 million and $6.0 million for the three months ended December 31,
2005, March 31, 2006, September 30, 2006, December 31, 2006 and September 30,
2008,
19
Table of Contents
respectively. We had no
derivative gains or losses for the three months ended June 30, 2006, March 31,
2007, June 30, 2007, September 30, 2007, December 31, 2007 and March 31,
2008.
For the three months ended June 30, 2008, we recognized a $5.7
million derivative gain with respect to futures contracts purchased to hedge
our exposure to a fixed price contract for which we bid, and we recognized a
$6.0 million derivative loss during the three months ending September 30,
2008 with respect to the sale of certain of these contracts (see note 6 to the
accompanying condensed consolidated financial statements). Commencing with the
adoption of our revised natural gas hedging policy in February 2007 (as
revised in May 2008), 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.
At September 30, 2008, we had $0.8 million on deposit in margin
accounts.
The decrease in the value of our futures positions and any required
margin deposits on our futures contracts that are in a loss position could
significantly impact our financial condition in the future.
Risk Management
Activities
Our risk management
activities, including the revised natural gas hedging policy adopted by our
board of directors in February 2007 and revised by our board of directors
on May 29, 2008 are discussed in Part II, Item 7 (Managements
Discussion and Analysis of Financial Condition and Results of Operation) of our
annual report on Form 10-K for the year ended December 31, 2007 and
our current report on Form 8-K dated June 19, 2008, which discussion
is incorporated herein by reference.
On April 18, 2008, we purchased certain natural gas futures
contracts to attempt to economically hedge our exposure to cash flow
variability related to the commodity component of an LNG supply contract for
which we had submitted a fixed-price bid. As previously disclosed in our Form 8-K
dated June 19, 2008, the supply contract for which the futures contracts
were purchased was awarded to our competitor. We protested the award of the
contract to our competitor and ultimately we were awarded a portion of the
contract representing approximately one-third of the contract volumes.
Ultimately, we realized a net loss of $0.3 million related to the sale of the
futures contracts purchased with respect to the portion of the fixed-price
contract that we were not awarded. The remaining futures contracts currently qualify
for hedge accounting as cash flow hedges under SFAS 133.
Critical Accounting Policies
For
the period covered by this report, there have been no material changes to the
critical accounting policies we use and have explained in our annual report on Form 10-K
for the fiscal year ended December 31, 2007.
Recently Issued Accounting
Pronouncements
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 does not require any new fair value
measurements. In February 2008, the FASB amended SFAS 157 to exclude SFAS
13, Accounting for Leases. In addition, the FASB delayed the effective date
of SFAS 157 for non-financial assets and liabilities to fiscal years beginning
after November 15, 2008. We adopted the provisions of SFAS 157 related to
our financial assets and liabilities on January 1, 2008, which did not
have a material impact on our financial statements. In accordance with the new
standard, we have provided additional disclosures which are included in the
notes to our condensed consolidated financial statements. With respect to our non-financial assets and
liabilities, we are currently evaluating the impact, if any, SFAS 157 may have
on our financial statements.
20
Table of Contents
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.
Unrealized gains and losses arising subsequent to adoption are reported in
earnings. We adopted this statement as of January 1, 2008 and elected not
to apply the fair value option to any of our financial instruments.
In December 2007,
the FASB finalized the provisions of the Emerging Issues Task Force (EITF)
issue No. 07-1,
Accounting for
Collaborative Arrangements
(EITF 07-1). EITF 07-1
provides guidance and required financial statement disclosures for
collaborative arrangement. EITF 07-01 is effective for financial
statements issued for fiscal years beginning after December 15, 2008. We
are currently evaluating the impact, if any, EITF 07-1 may have on
our financial statements.
In December 2007, the FASB issued Statement of
Financial Accounting Standards No. 141(R),
Business Combinations
(SFAS 141(R)). SFAS 141(R) provides
new accounting guidance and disclosure requirements for business combinations.
SFAS 141(R) is effective for business combinations which occur in the
first fiscal year beginning on or after December 15, 2008.
In December 2007, the FASB issued Statement of
Financial Accounting Standard No. 160,
Minority
Interests in Consolidated Financial Statementsan amendment of ARB No. 51
(SFAS 160). SFAS 160 provides new accounting guidance and
disclosure and presentation requirements for non-controlling interests in a
subsidiary. SFAS 160 is effective for the first fiscal year beginning on
or after December 15, 2008. We are currently evaluating the impact, if
any, SFAS 160 may have on our financial statements.
In March 2008, the
FASB issued Statement of Financial Accounting Standards No. 161, Disclosures
about Derivative Instruments and Hedging Activities, an amendment of SFAS 133
(SFAS 161). SFAS 161 requires disclosures of how and why an entity uses
derivative instruments, how derivative instruments and related hedged items are
accounted for and how derivative instruments and related hedged items affect an
entitys financial position, financial performance, and cash flows. SFAS 161 is
effective for fiscal years beginning after November 15, 2008, with early
adoption permitted. We are currently evaluating the impact, if any, SFAS 161
may have on our financial statements.
In April 2008,
the FASB Staff Position (FSP) issued SFAS No. 142-3,
Determination of the Useful Life of Intangible Assets
(FSP SFAS 142-3). FSP SFAS 142-3 amends the factors that should be considered
in developing renewal or extension assumptions used to determine the useful
life of a recognized intangible asset under SFAS No. 142,
Goodwill and Other Intangible Assets
. The
intent of FSP SFAS 142-3 is to improve the consistency between the useful life
of a recognized intangible asset under SFAS 142 and the period of expected cash
flows used to measure the fair value of the asset under SFAS No. 141
(revised 2007),
Business Combinations
,
and other U.S. generally accepted accounting principles (GAAP). FSP SFAS
142-3 is effective for fiscal years beginning after December 15, 2008 and
we will adopt the pronouncement in the first quarter of fiscal year 2009. We
are currently evaluating the effect that the adoption of FSP SFAS 142-3 will
have on our results of operation and financial position or cash flows, if any,
but do not expect it will have a material impact.
In May 2008,
the FASB issued SFAS No. 162,
The
Hierarchy of Generally Accepted Principles
(SFAS 162). SFAS 162
identifies the sources of accounting principles and the framework for selecting
the principles used in the preparation of financial statements of
nongovernmental entities that are presented in conformity with generally
accepted accounting principles (the GAAP hierarchy). SFAS 162 will become
effective 60 days following the SECs approval of the Public Company Accounting
Oversight Board amendments to AU 411,
The
Meaning of Present Fairly in Conformity With Generally Accepted Accounting
Principles
. We do not expect the adoption of SFAS 162 will have a
material impact on our results of operations and financial condition.
21
Table
of Contents
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,
|
|
|
|
2007
|
|
2008
|
|
2007
|
|
2008
|
|
Statement of Operations Data::
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
100.0
|
%
|
100.0
|
%
|
100.0
|
%
|
100.0
|
%
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
Cost of sales
|
|
69.3
|
|
74.0
|
|
72.8
|
|
77.3
|
|
Derivative (gains) losses
|
|
|
|
17.1
|
|
|
|
0.3
|
|
Selling, general and administrative
|
|
32.6
|
|
32.3
|
|
29.8
|
|
35.2
|
|
Depreciation and amortization
|
|
6.2
|
|
6.6
|
|
5.8
|
|
6.6
|
|
Total operating expenses
|
|
108.1
|
|
130.0
|
|
108.4
|
|
119.4
|
|
Operating loss
|
|
(8.2
|
)
|
(30.0
|
)
|
(8.4
|
)
|
(19.4
|
)
|
|
|
|
|
|
|
|
|
|
|
Interest income, net
|
|
4.8
|
|
0.2
|
|
2.6
|
|
1.2
|
|
Other income (expense), net
|
|
(0.2
|
)
|
(0.1
|
)
|
(0.3
|
)
|
0.0
|
|
Equity in gains (losses) of equity method
investee
|
|
|
|
0.1
|
|
|
|
(0.1
|
)
|
Loss before income taxes
|
|
(3.5
|
)
|
(29.8
|
)
|
(6.1
|
)
|
(18.3
|
)
|
Income tax expense
|
|
(1.8
|
)
|
(0.3
|
)
|
(0.7
|
)
|
(0.2
|
)
|
Minority interest in net income
|
|
|
|
(0.0
|
)
|
|
|
(0.0
|
)
|
Net loss
|
|
(5.3
|
)
|
(30.2
|
)
|
(6.8
|
)
|
(18.5
|
)
|
Three Months Ended
September 30, 2008 Compared to Three Months Ended September 30, 2007
Revenue.
Revenue
increased by $6.1 million to $35.3 million in the three months ended September 30,
2008, from $29.2 million in the three months ended September 30,
2007. This increase was primarily the result of an increase in our average
price per gallon between periods. Our effective price per gallon was $1.57 in
the three months ended September 30, 2008, which represents a $0.35 per
gallon increase from $1.22 in the three months ended September 30, 2007.
Revenue also increased between periods as we recorded $5.6 million of
revenue related to fuel tax credits in the third quarter of 2008, compared to
$4.6 million in the third quarter of 2007.
We also experienced a $0.1 million increase in station construction
revenues between periods. These
increases were offset by the decrease in the number of gallons delivered
between periods from 20.0 million gasoline gallon equivalents to 18.7 million
gasoline gallon equivalents. The decrease in volume was primarily related to
the loss of a portion of the new City of Phoenix LNG supply contract that began
July 1, 2008.
Cost of sales.
Cost of sales
increased by $5.8 million to $26.1 million in the three months ended September 30,
2008, from $20.3 million in the three months ended September 30, 2007. Our
cost of sales primarily increased between periods as our effective cost per
gallon rose to $1.39 in the three months ended September 30, 2008, which
represents a $0.38 per gallon increase over the three months ended September 30,
2007. Also contributing to the increase
in cost of sales was an increase in station construction cost of $0.2 million
between periods. Offsetting these
increases was a $1.8 million decrease in costs related to delivering less CNG
and LNG between periods.
Derivative (gains) losses.
Derivative
losses increased to $6.0 million in the three months ended September 30,
2008, from $0.0 million in the three months ended September 30, 2007.
This increase was due to a loss we recognized in the three month period ended September 30,
2008 with respect to the sale of certain futures contracts we purchased in
conjunction with the portion of a fixed-price bid on a LNG supply contract that
we were not awarded (see note 6 to the accompanying condensed consolidated
financial statements). We did not sell or own any futures contracts during the three
months ended September 30, 2007.
Selling, general and administrative.
Selling,
general and administrative expenses increased by $1.9 million to
$11.4 million in the three months ended September 30, 2008, from
$9.5 million in the three months ended September 30, 2007. Our stock option expense accounted for $1.1
million of the increase between periods primarily due to options issued in 2008
for new employees. Our marketing
expenses also increased $0.9 million between periods due to certain advertising
we conducted at the Ports of Los Angeles and Long Beach and costs we incurred
to support Proposition 10.
22
Table of Contents
Depreciation and amortization.
Depreciation
and amortization increased by $0.5 million to $2.3 million in the
three months ended September 30, 2008, from $1.8 million in the three
months ended September 30, 2007. This increase was primarily related to
the result of additional amortization expense in the three months ended September 30,
2008 related to the amortization of the identifiable intangible asset recorded
in connection with the acquisition of our 70% interest in DCE in August 2008
and our increased property and equipment balances between periods, primarily
related to our expanded station network.
Interest income, net.
Interest
income, net, decreased by $1.3 million from $1.4 million in the three
months ended September 30, 2007, to $0.1 million for the three months
ended September 30, 2008. This decrease was primarily the result of a
decrease in interest income in the three months ended September 30, 2008
due to lower average cash balances on hand during the three months ended September 30,
2008 as compared to the third quarter of 2007.
We also incurred interest expense in the third quarter of 2008 related
to the debt we incurred to acquire our interest in DCE in August 2008.
Other income (expense), net.
There
was no significant change in other income (expense), net, between the three
months ended September 30, 2007 and the three months ended September 30,
2008.
Equity in
gains (losses) of equity method investee.
During
the three months ended September 30, 2008, we recognized $20,000 of equity
gains related to our joint venture in Peru. The CNG station owned by the joint
venture opened in April 2008.
Minority
interest in net income.
During the three months
ended September 30, 2008, we recorded $14,000 for the minority interest in
the net income of DCE. The minority
interest represents the 30% interest of our joint venture partner. The results
of DCEs operations have been included in the consolidated financial statements
since August 15, 2008, the date of acquisition.
Nine Months Ended September 30,
2008 Compared to Nine Months Ended September 30, 2007
Revenue.
Revenue increased by
$11.8 million to $99.8 million in the nine months ended September 30,
2008, from $88.0 million in the nine months ended September 30, 2007.
This increase was primarily the result of an increase in our average price per
gallon between periods. Our effective price per gallon was $1.52 in the nine
months ended September 30, 2008, which represents a $0.27 per gallon
increase from $1.25 in the nine months ended September 30, 2007. Revenue
also increased between periods as we recorded $15.5 million of revenue
related to fuel tax credits in the first nine months of 2008 compared to $12.8
million in the first nine months of 2007. These increases were offset by the
decrease in the number of gallons delivered between periods from 57.1 million
gasoline gallon equivalents to 54.8 million gasoline gallon equivalents. The
loss of a portion of the City of Phoenix LNG supply contract after June 30,
2008, the loss of an LNG O&M contract related to a facility that was
relocated, and the loss of a CNG supply contract with a customer who decided to
procure their own natural gas supply together accounted for 4.7 million
gasoline gallon equivalents of the decrease.
These decreases were offset by the addition of 1.6 million gasoline
gallon equivalents due to the addition of new customers (OCTA, Santa Cruz
Metropolitan Transit Authority, City of Los Angeles, Southland Transit,
Regional Transit Commission of Nevada, and Regional Transit Authority of Ohio),
0.2 million gasoline gallon equivalents related to our interest in our joint
venture in Peru, and 0.6 million gasoline gallon equivalents from our 70%
interest in DCE. We also experienced a $2.7 million decrease in station
construction revenues between periods.
Cost of sales.
Cost of sales
increased by $13.0 million to $77.1 million in the nine months ended September 30,
2008, from $64.1 million in the nine months ended September 30, 2007. Our
cost of sales increased between periods as our effective cost per gallon rose
to $1.40 in the nine months ended September 30, 2008, which represents a
$0.33 per gallon increase over the nine months ended September 30, 2007.
Offsetting the increase in our effective cost per gallon was the decrease in station
construction costs of $2.4 million between periods and a $3.3 million decrease
in costs related to delivering less CNG and LNG between periods.
Derivative (gains) losses.
Derivative
losses increased to $0.3 million in the nine months ended September 30,
2008, from $0.0 million in the nine months ended September 30, 2007.
This increase was due to a loss we recognized in the nine month period ended September 30,
2008 on futures contracts we purchased in April 2008 in conjunction with a
fixed-price bid on a LNG supply contract we had submitted (see note 6 to the
accompanying condensed consolidated financial statements) and sold in July 2008.
We did not sell or own any futures contracts during the nine months ended September 30,
2007.
23
Table of Contents
Selling, general and administrative.
Selling,
general and administrative expenses increased by $8.8 million to
$35.1 million in the nine months ended September 30, 2008, from
$26.3 million in the nine months ended September 30, 2007. A
significant portion of this increase related to a $4.2 million increase in our
marketing expenses due to certain advertising we conducted related to the Ports
of Los Angeles and Long Beach and costs we incurred to support Proposition 10. Stock option expense between periods
increased $2.4 million due to options issued in 2008 for new employees. There
was also an increase of $0.7 million in salaries and benefits between periods
primarily related to the hiring of additional employees. Our headcount
increased from 118 at September 30, 2007 to 134 at September 30, 2008. Our
professional service fees increased $0.8 million between periods, primarily for
legal, audit and consulting services related to our obligations as a public
company. Our business insurance costs
increased $0.5 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 $1.5 million to $6.6 million in the
nine months ended September 30, 2008, from $5.1 million in the nine
months ended September 30, 2007. This increase was due to additional
depreciation expense in the nine months ended September 30, 2008 related
to increased property and equipment balances between periods, primarily related
to our expanded station network, and due to the amortization of the
identifiable intangible asset recorded in connection with the acquisition of
our 70% interest in DCE, in August 2008.
Interest income, net.
Interest
income, net, decreased by $1.1 million from $2.3 million in the nine
months ended September 30, 2007, to $1.2 million for the nine months ended
September 30, 2008. This decrease was primarily the result of a decrease
in interest income in the nine months ended September 30, 2008 due to
lower average cash balances on hand between periods.
Other income (expense), net.
Other
income (expense), net, was $11,000 of income in the nine months ended September 30,
2008, as compared to $229,000 of expense in the nine months ended September 30,
2007. The increase was primarily related to the write-off of certain costs
related to station relocation in the nine months ended September 30, 2007
that did not occur in the nine months ended September 30, 2008, and the
sale of certain assets in the nine months ended September 30, 2008 that
did not occur in the nine months ended September 30, 2007.
Equity in
gains (losses) of equity method investee.
During the nine months ended September 30,
2008, we recognized $120,000 of equity losses related to our joint venture in
Peru. The CNG station owned by the joint venture opened in April 2008.
Minority
interest in net income.
During the nine months
ended September 30, 2008, we recorded $14,000 for the minority interest in
the net income of DCE. The minority
interest represents the 30% interest of our joint venture partner. The results
of DCEs operations have been included in the consolidated financial statements
since August 15, 2008, the date of acquisition.
Liquidity and
Capital Resources
Historically,
our principal sources of liquidity have consisted of cash provided by
operations and financing activities, 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. On August 15, 2008, in connection
with our acquisition of 70% of the membership interests of DCE, we entered into
a credit agreement with PlainsCapital Bank pursuant to which we borrowed $18.0
million under a term loan and an additional $4.2 million (as of September 30,
2008) under a line of credit (see note 11 to the accompanying condensed
consolidated financial statements). On September 24, 2008, we sold 319,488
shares
of our common stock at a price of $15.65 per share
to Boone Pickens Interests, Ltd. for proceeds of approximately $5.0
million. On November 3, 2008 we sold
4,419,192 units of common stock and warrants for $7.92 per unit (See note 20 to
the accompanying condensed consolidated financial statements for a discussion
of the transaction) and we raised net proceeds of approximately $32.5 million
after deducting offering costs.
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,
24
Table of Contents
our support for Proposition 10 and for working capital
for our expansion. We may also seek to
acquire companies or assets in the natural gas fueling infrastructure, services
and production industries. We financed
our operations in the first nine months of 2008 primarily through cash on hand.
At September 30,
2008, we had total cash and cash equivalents of $30.4 million compared to
$67.9 million at December 31, 2007.
Following the sale of 4,419,192 units of common stock and warrants, (consisting
of an aggregate of 4,419,492 shares of common stock, Series I Warrants to
purchase up to an aggregate of 3,314,394 shares of common stock, and Series II
Warrants to purchase up to an aggregate of 1,136,364 shares of common stock) in
a transaction that closed November 3, 2008, we had total cash and cash
equivalents of approximately $38.5 million.
We did not have any short-term investments at September 30, 2008 as
we sold them all during the nine month periods ended September 30,
2008. We had $12.5 million of short-term
investments at December 31, 2007.
Cash
provided by operating activities was $7.8 million for the nine months ended September 30,
2008, compared to cash provided by operating activities of $8.6 million for the
nine months ended September 30, 2007.
The decrease in operating cash flow resulted primarily from an increase
in our net loss between periods.
Offsetting this decrease was a $13.3 million increase between periods
related to net returns of LNG truck deposits.
The remaining changes primarily resulted from changes in working capital
balances, which were mostly due to timing differences related to the various
cash flows between periods.
Cash
used in investing activities was $72.7 million for the nine months ended September 30,
2008, compared to $45.1 million for the nine months ended September 30,
2007. Our purchases of property and equipment were $59.8 million during the
first nine months of 2008. Included in
purchases of property and equipment in the first nine months of 2008 was $39.9
million of construction costs related to our LNG liquefaction plant in
California. In the first nine months of
2007, we purchased $14.8 million of short-term investments with our initial
public offering proceeds from May 2007. In the first nine months of 2008,
all of our short-term investments were sold or matured resulting in net cash
proceeds of $12.5 million. In August 2008,
we purchased a 70% interest in DCE and our total cash outlay for the
acquisition including transaction costs was $19.6 million. We also made an investment during the first
nine months of 2008 of $3.2 million in the Vehicle Production Group, LLC, a
company developing a CNG taxi and a paratransit vehicle, and transferred $2.5
million of our cash balance to a restricted account in accordance with our August 2008
credit agreement with PlainsCapital Bank.
Cash
provided by financing activities for the nine months ended September 30,
2008 was $27.3 million, compared to $110.3 million for the nine months ended September 30,
2007. In May 2007, we completed our
initial public offering, which raised $110.3 million during the nine month
period ended September 30, 2007. In
August 2008, we borrowed $22.1 million to fund the acquisition of our
interest in DCE, and to pay other amounts related to the transaction. In addition, in September 2008, we
issued and sold 319,488 shares of our common stock for an aggregate purchase
price of approximately $5.0 million.
Our
financial position and liquidity are, and will be, influenced by a variety of
factors, including our ability to generate cash flows from operations, deposits
and margin calls on our futures positions, the level of any outstanding
indebtedness and the interest we are obligated to pay on this indebtedness, 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 through debt or equity financings.
We anticipate we have enough cash to fund our 2008 capital expenditure budget.
We anticipate that we will need to raise additional capital in 2009 to fund our
2009 capital expenditure budget in full; however, the timing and necessity of any
future capital raise will depend primarily on the rate of new station
construction and other capital expenditures. We may also seek to acquire
companies or assets in the natural gas fueling infrastructure, services and
production industries. If we do so, we
may need to raise additional capital as necessary to fund any such acquisitions
as we did not contemplate any acquisitions in our 2008 capital expenditure
plan.
Capital Expenditures
We
expect to make capital expenditures, net of grant proceeds, of approximately
$80.7 million in 2008 to construct new natural gas fueling stations, to
complete construction of our LNG liquefaction plant in California, and for
general corporate purposes. Of the $80.7 million, we have budgeted
approximately $49.9 million during 2008 to complete construction of our
LNG liquefaction plant in California, which we anticipate will be operational
in November 2008. We also anticipate using approximately $3.4 million to
finance the purchase of natural gas vehicles by our customers during 2008.
25
Table
of Contents
Contractual
Obligations
The
following represents the scheduled maturities of our contractual obligations as
of September 30, 2008:
|
|
Payments Due by Period
|
|
Contractual Obligations:
|
|
Total
|
|
Remainder of
2008
|
|
2009 and
2010
|
|
2011 through
2013
|
|
2014 and
beyond
|
|
Long-term debt and capital lease
obligations (a)
|
|
$
|
26,863,390
|
|
$
|
540,929
|
|
$
|
6,826,359
|
|
$
|
19,496,102
|
|
$
|
|
|
Operating lease commitments (b)
|
|
10,405,454
|
|
431,868
|
|
3,413,464
|
|
4,594,567
|
|
1,965,555
|
|
Take-or-pay LNG purchase contracts (c)
|
|
8,343,000
|
|
2,455,500
|
|
4,890,000
|
|
997,500
|
|
|
|
Construction contracts (d)
|
|
14,899,898
|
|
14,899,898
|
|
|
|
|
|
|
|
Other long-term contract liabilities (e)
|
|
9,944,393
|
|
9,944,393
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
70,456,135
|
|
$
|
28,272,588
|
|
$
|
15,129,823
|
|
$
|
25,088,169
|
|
$
|
1,965,555
|
|
(a) Consists of long-term debt and
capital lease obligations under a lease of capital equipment used to finance
such equipment.
(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 three take or pay
contracts. In October 2007, we entered into a 10-year contingent
take-or-pay commitment for 45,000 LNG gallons per day from an LNG plant to be
constructed in Arizona, which commitment is not reflected in the table above
because of the contingent nature of the obligation. This obligation is
contingent on the successful commencement of operations at the LNG plant.
(d) Consists of our obligations to fund
various fueling station construction projects, net of amounts funded through September
30, 2008, 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 and contracts we have entered into to acquire
certain equipment and services related to the construction of our LNG plant in
California. Amounts shown are net of amounts funded through September 30,
2008.
Off-Balance Sheet
Arrangements
At September 30,
2008, 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
$9.5 million,
·
three
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
equipment purchases 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 for which we will not be reimbursed.
26
Table of Contents
We
have entered into contracts with three vendors to purchase LNG that require us
to purchase minimum volumes from the vendors. One of the contracts expires in December 2008,
one expires in March 2009 and the other contract expires in June 2011.
The minimum commitments under these three contracts are included in the table
set forth under Take-or-pay LNG purchase contracts above. In October 2007,
we entered into a contingent take-or-pay contract from an LNG plant that is
under construction that is not included in the table 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
building an LNG liquefaction plant. We have budgeted approximately $49.9 million
in 2008 to finish construction of 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 million 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. 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 58% of our cost of sales for 2007 and 64% of our cost of
sales for the nine months ended September 30, 2008. Prices for natural gas
over the eight-year and nine-month period from December 31, 1999 through September 30,
2008, 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, 2008, the NYMEX index
price of natural gas was $8.40 per Mcf.
To
reduce price risk caused by market fluctuations in natural gas, we may enter
into exchange traded natural gas futures contracts. These arrangements also
expose us to the risk of financial loss in situations where the other party to
the contract defaults on its contract or there is a change in the expected
differential between the underlying price in the contract and the actual price
of natural gas we pay at the delivery point.
We account for these futures contracts in accordance with SFAS 133. Under this standard, the
accounting for changes in the fair value of a derivative depends upon whether
it has been designated in a hedging relationship and, further, on the type of
hedging relationship. To qualify for designation in a hedging relationship,
specific criteria must be met and appropriate documentation maintained.
Historically, our derivative instruments have not qualified for hedge
accounting under SFAS 133. We did not
have any derivative instruments during the year ended December 31, 2007,
and had certain derivative instruments at September 30, 2008 to hedge a
fixed-price LNG supply contract with a customer that did qualify for hedge
accounting.
The
fair value of the futures contracts we use is based on quoted prices in active
exchange traded or over the counter markets. The fair value of these futures
contracts is continually subject to change due to changing market
conditions. In an effort to mitigate the
volatility in our earnings related to futures activities, in February 2007,
our board of directors adopted a revised natural gas hedging policy which
restricts our ability to purchase natural gas futures contracts and offer
fixed-price sales contracts to our customers. This policy was further revised
by our board of directors in May 2008.
We plan to structure prospective futures contracts so that they will be
accounted for as cash flow hedges under SFAS 133, but we cannot be certain
they will qualify.
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We
have prepared a sensitivity analysis to estimate our exposure to market risk
with respect to the futures contracts we still hold as of the date of this
report to hedge the fixed-price component of the portion of the City of Phoenix
LNG supply contract we were awarded. If
the price of natural gas were to fluctuate (increase or decrease) by 10% from the
price quoted on NYMEX on September 30, 2008 ($8.40 per Mcf), we could
expect a corresponding fluctuation in the value of the contracts of
approximately $0.3 million.
We
have also 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,
2008. 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
customers 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
|
%
|
$
|
(0.3
|
)
|
Price cap contracts
|
|
10.0
|
%
|
$
|
(0.3
|
)
|
This
table does not include two 2.1 million LNG gallon per year renewal options
beginning April 1, 2009 that one of our customers possesses related to an
LNG price cap contract. Had the contract
been included, assuming both renewal periods were exercised, the resulting
amount for the price cap contracts would be $(0.6) million.
Item
4. Controls and Procedures
Not applicable
Item 4T.
Controls
and Procedures
Disclosure
Controls and Procedures
We
maintain disclosure controls and procedures that are designed to ensure that
information required to be disclosed in the reports we file or submit under the
Exchange Act is recorded, processed, summarized and reported within the time
periods specified in the Securities and Exchange Commissions rules and
forms and that such information is accumulated and communicated to our
management, including our Chief Executive Officer and Chief Financial Officer,
as appropriate, to allow timely decisions regarding required disclosure. We
carried out an evaluation, under the supervision of and with the participation
of our management, including our Chief Executive Officer and Chief Financial
Officer, of the effectiveness of the design and operation of our disclosure
controls and procedures. Based on this evaluation, our Chief Executive Officer
and Chief Financial Officer concluded that our disclosure controls and
procedures were effective as of the end of the period covered by the report.
Changes in
Internal Control over Financial Reporting
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.
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PART II.
OTHER
INFORMATION
Item
1. Legal Proceedings
We may
become party to various legal actions that arise in the ordinary course of our
business. We are currently engaged in
commercial litigation with an LNG supplier but we do not believe the outcome of
the litigation will have a material adverse effect on our consolidated
financial position or results of operations.
During the course of our operations, we are also subject to audit by tax
authorities for varying periods in various federal, state, local, and foreign
tax jurisdictions. Disputes may arise
during the course of such audits as to facts and matters of law. It is impossible at this time to determine
the ultimate liabilities that we may incur resulting from any lawsuits, claims
and proceedings, audits, commitments, contingencies and related matters or the
timing if these liabilities, if any. If
these matters were to be ultimately resolved unfavorably, an outcome not
currently anticipated, it is possible that such outcome could have a material
adverse effect upon our consolidated financial position or results of
operations. However, we believe that the
ultimate resolution of such actions will not have a material adverse affect on
our consolidated financial position, results of operations, or liquidity.
Item
1A. Risk Factors
An investment in our common stock involves a substantial risk of loss.
You should carefully consider the risk factors discussed below together with the
risk factors in Part I, Item 1A of our annual report on Form 10-K for the year
ended December 31, 2007 and all of the other information included in this
report before you decide to purchase shares of our common stock. We believe the
risks and uncertainties described below are the most significant we face. The
occurrence of any of the following risks could harm our business. In that case,
the trading price of our common stock could decline. Additional risks and
uncertainties not presently known to us or that we currently deem immaterial
may also impair our operations.
We have
a history of losses and may incur additional losses in the future.
For
the nine month period ended September 30, 2008, we incurred pre-tax losses
of $18.3 million, which includes derivative losses of $0.3 million. In 2006 and
2007, we incurred pre-tax losses of $89.8 million and $7.7 million,
respectively, which include derivative losses of $79.0 million and
$0.0 million, respectively. In 2004 and 2005, we reported pre-tax net
income of $3.8 million and $28.9 million, respectively, but we would have
reported pre-tax net losses related our operations if we excluded derivative
gains of $10.6 million and $44.1 million, respectively. For the
three-month period ended September 30, 2008, we incur a net loss of $10.5
million, which includes a previously disclosed $6.0 million loss on the sale of
natural gas futures contracts, and $500,000 in expenses associated with our
support for Proposition 10, the California Alternative Fuel Vehicles and
Renewable Energy ballot initiative. In order to execute our strategy, we
must continue to invest in developing the natural gas vehicle fuel market, and
our natural gas sales activities and station operations may not achieve or
maintain profitability. If our natural gas sales activities and station
operations continue to lose money, our business will suffer and the price of
our common stock may drop.
We will need to raise debt or equity capital to have
sufficient cash to fund our capital expenditure program and an inability to
access the capital markets may impair our ability to grow our business.
We
anticipate that, in order to raise additional funds to fund our 2009 capital
expenditure program in full and provide resources for potential acquisition
activity or other strategic transactions and vehicle financing programs, we
will need to pursue additional equity financing options, which may not be
available on terms favorable to us or at all. We may also pursue debt
financing options including, but not limited to, the sale of convertible promissory
notes or commercial bank financing. Recent and severe lack of liquidity in the
debt capital markets and volatility and rapidly falling prices in the equity
capital markets have severely and adversely affected capital raising
opportunities. If we are unable to obtain debt or equity financing in
amounts sufficient to fund our 2009 capital expenditure program in full and
provide resources for acquisitions or other strategic transactions, we will be
forced to suspend or curtail certain of our planned expansion activities,
including new station construction, potential acquisitions or other strategic
transactions, and vehicle financing programs, which could harm our business,
results of operations, and future prospects.
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We invested $18.7 million supporting Proposition 10, which
was not approved by California voters in the November election.
We
invested a total of approximately $18.7 million, of which approximately $15
million was invested in the fourth quarter of 2008, supporting the California
Alternative Fuel Vehicles and Renewable Energy Initiative, or Proposition 10, a
California statewide ballot initiative that called for the creation of a
state-administered $5.0 billion fund through the sale of bonds to support
development of alternative fuels and energy in California. Proposition 10
failed to pass and this may result in investors and securities analysts
lowering their projections and expectations for our future financial
performance and growth, which may harm our stock price. Our results for
the fourth quarter of 2008 will include substantially higher than anticipated
expenses as a result of the $15 million we spent in the fourth quarter of 2008
supporting Proposition 10.
Failure to comply with the terms of our Credit Agreement with
PlainsCapital Bank could impair our rights in Dallas Clean Energy, LLC and
other secured property.
We
recently acquired a 70% interest in Dallas Clean Energy, LLC (DCE), a
partnership that manages a biomethane production facility at the McCommas Bluff
landfill in Dallas, Texas and holds a lease to the associated landfill gas
development rights. We borrowed $18.0 million from PlainsCapital Bank to
fund the acquisition and obtained a $12 million line of credit from
PlainsCapital to finance capital improvements of the gas processing plant and
pay certain costs and expenses of the acquisition. We have utilized $4.2
million of the line of credit as of October 28, 2008. To secure our
obligations under the Credit Agreement, we granted PlainsCapital Bank a
security interest in 45 of our LNG tanker trailers, certain accounts receivable
and inventory, our note receivable from, and our membership interests in, DCE.
If we default on the Credit Agreement or otherwise fail to comply with any of
the negative or affirmative covenants of the Credit Agreement, PlainsCapital
Bank may declare all of the obligations and indebtedness under the Credit Agreement
(and related documents) due and payable. In such a scenario, we may lose
our right, title and interest in the property that secures such obligations and
indebtedness.
Our growth depends in part on environmental regulations and
programs mandating the use of cleaner burning fuels, and modification or repeal
of these regulations may adversely impact our business.
Our
business depends in part on environmental regulations and programs in the
United States that promote or mandate the use of cleaner burning fuels,
including natural gas for vehicles. In particular, the Ports of Los
Angeles and Long Beach have adopted the San Pedro Clean Air Action Plan, which
calls for the replacement of 5,300 trucks that meet certain clean truck
standards. Industry participants with a vested interest in gasoline and
diesel, many of which have substantially greater resources than we do, invest
significant time and money in an effort to influence environmental regulations
in ways that delay or repeal requirements for cleaner vehicle emissions.
An economic recession may result in the delay, amendment or waiver of
environmental regulations or the San Pedro Clean Air Action Plan due to the
perception that they impose increased costs on the transportation industry that
cannot be absorbed in a contracting economy. The delay, repeal or
modification of federal or state regulations or programs that encourage the use
of cleaner vehicles, and in particular the San Pedro Clean Air Action Plan,
could have a detrimental effect on the U.S. natural gas vehicle industry,
which, in turn, could slow our growth and adversely affect our business.
Our growth depends in part on tax and related government
incentives for clean burning fuels. A reduction in these incentives would
increase the cost of natural gas fuel and vehicles for our customers and could
significantly reduce our revenue.
Our
business depends in part on tax credits, rebates and similar federal, state and
local government incentives that promote the use of natural gas as a vehicle
fuel in the United States. The federal excise tax credit of $0.50 per
gasoline gallon equivalent of CNG and liquid gallon of LNG sold for vehicle
fuel use, which began on October 1, 2006, is scheduled to expire December 31,
2009. Based on the service relationship we have with our customers,
either we or our customers are able to claim the credit. In 2007 and
during the first nine months of 2008, we recorded $17.0 million and $15.5
million of revenue, respectively, related to fuel tax credits, representing
approximately 14.5% and 15.5%, respectively, of our total revenue during the
period. The failure to extend the federal excise tax credit for natural
gas, or the repeal of federal or state tax credits for the purchase of natural
gas vehicles or natural gas fueling equipment, could have a detrimental effect
on the natural gas vehicle industry, which, in turn, could adversely affect our
business and results of operations. In addition, if grant funds were no
longer available under existing government programs, the purchase of or
conversion to natural gas vehicles and station construction could slow and our
business and results of operations could be adversely affected. Any
reduction in tax revenues associated with an economic recession or slow-down
could result in a significant reduction in funds available for government
grants that support vehicle conversion and station construction and impair our
ability to grow our business.
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The volatility of natural gas prices could adversely impact
the adoption of CNG and LNG vehicle fuel and our business.
In
the recent past, the price of natural gas has been volatile, and this
volatility may continue. From the end of 1999 through October 28,
2008, the price for natural gas, based on the New York Mercantile Exchange
(NYMEX) daily futures data, ranged from a low of $1.65 per Mcf to a high of
$19.38 per Mcf. As of October 28, 2008, the NYMEX index price for
natural gas was $7.48 per Mcf. Increased natural gas prices affect the
cost to us of natural gas and will adversely impact our operating margins in
cases where we have committed to sell natural gas at a fixed price without a
futures contract or with an ineffective futures contract that does not fully
mitigate the price risk or where we otherwise cannot pass on the increased
costs to our customers. In addition, higher natural gas prices may cause
CNG and LNG to cost more than gasoline and diesel generally, which would
adversely impact the adoption of CNG and LNG as a vehicle fuel. Among the
factors that can cause price fluctuations in natural gas prices are changes in
domestic and foreign supplies of natural gas, domestic storage levels, crude
oil prices, the price difference between crude oil and natural gas, price and
availability of alternative fuels, weather conditions, level of consumer
demand, economic conditions, price of foreign natural gas imports, and domestic
and foreign governmental regulations and political conditions.
The use of natural gas as a vehicle fuel may not become
sufficiently accepted for us to expand our business.
To
expand our business, we must develop new fleet customers and obtain and fulfill
CNG and LNG fueling contracts from these customers. We cannot guarantee
that we will be able to develop these customers or obtain these fueling
contracts. Whether we will be able to expand our customer base will
depend on a number of factors, including: the level of acceptance and
availability of natural gas vehicles, the growth in our target markets of
fueling station infrastructure that supports CNG and LNG sales, and our ability
to supply CNG and LNG at competitive prices. Recently, disruption in the
capital markets has severely reduced the availability of debt financing.
If our potential customers are unable to access credit to purchase natural gas
vehicles it may make it difficult or impossible for them to invest in natural
gas vehicle fleets, which would impair our ability to grow our business.
A decline in the demand for vehicular natural gas would
reduce our revenue and negatively affect our ability to sustain our revenue
growth.
We
derive our revenue primarily from sales of CNG and LNG as a fuel for fleet
vehicles, and we expect this trend will continue. A downturn in demand
for CNG and LNG would adversely affect our revenue and ability to sustain and
grow our operations. Circumstances that could cause a drop in demand for
CNG and LNG vehicle fuel are described in other risk factors and include a
reduction in supply of natural gas, changes in governmental incentives, the
development of other alternative fuels and technologies, an economic slowdown,
prolonged disruption in the capital markets and a sustained increase in the
price of natural gas relative to gasoline and diesel.
If the prices of CNG and LNG do not remain sufficiently below
the prices of gasoline and diesel, potential fleet customers will have less
incentive to purchase natural gas vehicles or convert their fleets to natural
gas, which would decrease demand for CNG and LNG and limit our growth.
Natural
gas vehicles cost more than comparable gasoline or diesel powered vehicles
because converting a vehicle to use natural gas adds to its base cost. If
the prices of CNG and LNG do not remain sufficiently below the prices of
gasoline or diesel, fleet operators may be unable to recover the additional
costs of acquiring or converting to natural gas vehicles in a timely manner,
and they may choose not to use natural gas vehicles. Recent and extreme volatility
in oil and gas prices demonstrate that it is difficult to predict future transportation
fuel costs. This uncertainty, combined with higher costs for natural gas
vehicles, may cause potential customers to delay or reject converting their
fleets to run on natural gas. In that event, our growth would be slowed and our
business would suffer.
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Automobile and engine manufacturers produce very few
originally manufactured natural gas vehicles and engines for the U.S. and
Canadian markets, which may restrict our sales.
Limited
availability of natural gas vehicles restricts their wide scale introduction
and narrows our potential customer base. Currently, original equipment
manufacturers produce a small number of natural gas engines and vehicles, and
they may not make adequate investments to expand their natural gas engine and
vehicle product lines. For the North American market, there is only one
automobile manufacturer that makes natural gas powered passenger vehicles, and
manufacturers of medium and heavy-duty vehicles produce only a narrow range and
number of natural gas vehicles. Recent and significant economic challenges
confronted by North American car manufacturers may make it difficult or impossible
for them to introduce new natural gas vehicles in the North American market. Due
to the limited supply of natural gas vehicles, our ability to promote natural
gas vehicles and our sales may be restricted, even if there is demand.
Our ability to supply LNG to new and existing customers is
restricted by limited production of LNG and by our ability to source LNG
without interruption and near our target markets.
Production
of LNG in the United States is fragmented. LNG is produced at a variety of
smaller natural gas plants around the United States as well as at larger plants
where it is a byproduct of their primary natural gas production. It may
become difficult for us to obtain additional LNG without interruption and near
our current or target markets at competitive prices. If our current LNG
liquefaction plant, or any of those from which we purchase LNG, is damaged by
severe weather, earthquake or other natural disaster, or otherwise experiences
prolonged downtime, our LNG supply will be restricted. In addition, the
LNG liquefaction plant we are in the process of building in California may be
significantly delayed or never successfully commence full scale commercial
operations. If we are unable to supply enough of our own LNG or purchase
it from third parties to meet existing customer demand, we may be liable to our
customers for penalties. An LNG supply interruption would also limit our
ability to expand LNG sales to new customers, which would hinder our
growth. Furthermore, because transportation of LNG is relatively
expensive, if we are required to supply LNG to our customers from distant
locations, our operating margins will decrease on those sales.
LNG supply purchase commitments may exceed demand causing our
costs to increase and impact LNG sales margins.
Some
of our LNG supply agreements have take or pay commitments and the new
California LNG liquefaction plant has land lease and other fixed operating
costs regardless of production and sales levels. Should the market demand for LNG decline or if
demand under any existing or any future LNG supply contracts does not continue
or grow, overall operating and supply costs may increase and negatively impact our margins.
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Two of our third-party LNG suppliers may cancel their supply
contracts with us on short notice or increase their LNG prices, which would
hinder our ability to meet customer demand and increase our costs.
Two
third-party LNG suppliers, Williams Gas Processing Company and ExxonMobil
Corporation, supplied approximately 47% of the LNG we sold for the year ended December 31,
2007 and supplied 49% of the LNG we sold during the first nine months of
2008. Our contracts with these LNG suppliers generally may be terminated
by the supplier on short notice. In addition, under certain
circumstances, Williams Gas Processing Company may significantly increase the
price of LNG we purchase upon 24 hours notice if Williams costs to
produce LNG increases, and we may be required to reimburse Williams for certain
other expenses. Our contract with ExxonMobil Corporation, which supplied
15% of the LNG we sold for the year ended December 31, 2007 and 20% during
the first nine months of 2008, expires on March 31, 2009.
Furthermore, there are a limited number of LNG suppliers in or near the areas
where our LNG customers are located. It may be difficult to replace an
LNG supplier, and we may be unable to obtain alternate suppliers at acceptable
prices, in a timely manner or at all. If significant supply interruptions
occur, our ability to meet customer demand will be impaired, customers may
cancel orders and we may be subject to supply interruption penalties. If
we are subject to LNG price increases, our operating margins may be impaired
and we may be forced to sell LNG at a loss under our LNG supply contracts.
If we are unable to obtain natural gas in the amounts needed
on a timely basis or at reasonable prices, we could experience an interruption
of CNG or LNG deliveries or increases in CNG or LNG costs, either of which
could have an adverse effect on our business.
Some
regions of the United States and Canada depend heavily on natural gas supplies
coming from particular fields or pipelines. Interruptions in field
production or in pipeline capacity could reduce the availability of natural gas
or possibly create a supply imbalance that increases fuel price. We have
in the past experienced LNG supply disruptions due to severe weather in the
Gulf of Mexico and plant outages. If there are interruptions in field
production, pipeline capacity, equipment failure, liquefaction production or
delivery, we may experience supply stoppages which could result in our
inability to fulfill delivery commitments. This could result in our being
liable for contractual damages and daily penalties or otherwise adversely
affect our business.
We are in the process of constructing a new LNG liquefaction
plant, which could cost more to build and operate than we estimate and divert
resources and management attention.
We
are in the process of constructing an LNG liquefaction plant in California,
which we plan to operate upon completion. The construction, implementation and
operation of any plant of this nature has inherent risks. Permitting,
environmental issues, lack of materials and lack of human resources, among
other factors, could delay implementation and start up of the new LNG
liquefaction plant and affect the operation of the plant. Building the
new facility could also present increased financial exposure through project
delays, cost-overruns and incomplete production capability. As of the
date of this report, we anticipate the completion of the LNG liquefaction plant
will cost in the aggregate approximately $75 million, which is approximately
$20 to $25 million more than we originally anticipated due to design changes
and cost increases. If the new plant has higher than expected operating
costs and is not able to produce expected amounts of LNG, we may be forced to
sell LNG at a price below production costs and we may lose money. Additionally,
if the quality of LNG produced at the plant does not meet contractual
specifications, our customers may not be required to purchase it, which would
harm our business.
If we do not have effective futures contracts in place,
increases in natural gas prices may cause us to lose money.
From
2005 to September 30, 2008, we sold and delivered 31% of our total
gasoline gallon equivalents of CNG and LNG under contracts that provided a
fixed price or a price cap to our customers over terms typically ranging from
one to three years, and in some cases up to five years. At any given
time, however, the market price of natural gas may rise and our
33
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obligations
to sell fuel under fixed price contracts may be at prices lower than our fuel
purchase or production price if we do not have effective futures contracts in
place. This circumstance has in the past and may again in the future
compel us to sell fuel at a loss, which would adversely affect our results of
operations and financial condition. Commencing with the adoption of our
revised natural gas hedging policy in February 2007, we expect to purchase
futures contracts to hedge our exposure to variability related to substantial
fixed price contracts. However, such contracts may not be available or we
may not have sufficient financial resources to secure such contacts. In
addition, under our hedging policy, we may reduce or remove futures contracts
we have in place related to these contracts if such disposition is approved in
advance by our board of directors and derivative committee. If we are not
economically hedged with respect to our fixed price contracts, we will lose
money in connection with those contracts during periods in which natural gas
prices increase above the prices of natural gas included in our customers
contracts. As of September 30, 2008, we were economically hedged
with respect to one of our fixed price contracts that began July 1,
2008. Based on natural gas prices as of September 30, 2008, we incur
between $0.4 million and $0.5 million of costs to cover the increased
price of natural gas above the inherent price of natural gas embedded in our customers
fixed price and price cap contracts where we are not economically hedged over
the duration of the contracts. We expect the majority of these costs will
be incurred from October 1, 2008 through December 31, 2009.
Our futures contracts may not be as effective as we intend.
Our
purchase of futures contracts can result in substantial losses under various
circumstances, including if we do not accurately estimate the volume
requirements under our fixed price or price cap customer contracts when determining
the volumes included in the futures contracts we purchase, or we are required
to purchase a futures contract in connection with a bid proposal and ultimately
we are not awarded the entire contract or our customer does not fully perform
its obligations under the awarded contract. We also could incur
significant losses if a counterparty does not perform its obligations under the
applicable futures arrangement, the futures arrangement is economically
imperfect or ineffective, or our futures policies and procedures are not
properly followed or do not work as planned. Furthermore, we cannot
assure that the steps we take to monitor our futures activities will detect and
prevent violations of our risk management policies and procedures.
A decline in the value of our futures contracts may result in
margin calls that would adversely impact our liquidity.
We
are required to maintain a margin account to cover losses related to our
natural gas futures contracts. Futures contracts are valued daily, and if
our contracts are in loss positions at the end of a trading day, our broker
will transfer the amount of the losses from our margin account to a
clearinghouse. If at any time the funds in our margin account drop below
a specified maintenance level, our broker will issue a margin call that
requires us to restore the balance. Payments we make to satisfy margin
calls will reduce our cash reserves, adversely impact our liquidity and may
also adversely impact our ability to expand our business. Moreover, if we
are unable to satisfy the margin calls related to our futures contracts, our
broker may sell these contracts to restore the margin requirement at a
substantial loss to us. At October 28, 2008, we had $0.8 million on
deposit related to our futures contracts.
If our futures contracts do not qualify for hedge accounting,
our net income and stockholders equity will fluctuate more significantly from
quarter to quarter based on fluctuations in the market value of our futures
contracts.
We
account for our futures activities under Statement of Financial Accounting
Standards No. 133,
Accounting for
Derivative Instruments and Hedging Activities
, as amended
(SFAS 133), which requires us to value our futures contracts at fair
market value in our financial statements. Our futures contracts
historically have not qualified for hedge accounting, and therefore we have
recorded any changes in the fair market value of these contracts directly in
our consolidated statements of operations in the line item derivative (gains)
losses along with any realized gains or losses during the period. In the
future, we will attempt to qualify all of our futures contracts for hedge
accounting under SFAS 133, but there can be no assurances that we will be
successful in doing so. To the extent that all or some of our futures
contracts do not qualify for hedge accounting, we could incur significant
increases and decreases in our net income and stockholders equity in the
future based on fluctuations in the market value of our futures contracts from
quarter to quarter. For example, we experienced a derivative gain of
$33.1 million and $5.7 million for the three months ended September 30,
2005 and June 30, 2008, respectively, and experienced derivative losses of
$19.9 million, $0.3 million, $65 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, September 30, 2007, December 31, 2007 and March 31, 2008.
In July 2008, we sold certain contracts related to the derivative
instruments we purchased in April 2008 and we realized a loss of $6.0
million, which was reflected in the financial statements for the quarter ended September 30,
2008. Any negative fluctuations may cause our stock price to decline due
to our failure to meet or exceed the expectations of securities analysts or
investors.
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Natural gas operations entail inherent safety and
environmental risks that may result in substantial liability to us.
Natural
gas operations entail inherent risks, including equipment defects, malfunctions
and failures and natural disasters, which could result in uncontrollable flows
of natural gas, fires, explosions and other damages. For example,
operation of LNG pumps requires special training and protective equipment because
of the extreme low temperatures of LNG. LNG tanker trailers have also in the
past been, and may in the future be, involved in accidents that result in
explosions, fires and other damage. Improper refueling of LNG vehicles can
result in venting of methane gas. Additionally, CNG fuel tanks, if damaged or
improperly maintained, may rupture and the contents of the tank may rapidly
decompress and result in injury. These risks may expose us to liability
for personal injury, wrongful death, property damage, pollution and other
environmental damage. We may incur substantial liability and cost if
damages are not covered by insurance or are in excess of policy limits.
Our business is heavily concentrated in the western United
States, particularly in California and Arizona. Economic downturns in these
regions could adversely impact our business.
Our
operations to date have been concentrated in California and Arizona. For
the year ended December 31, 2007 and the nine months ended September 30,
2008, sales in California accounted for 40% and 45%, respectively, and sales in
Arizona accounted for 20% and 16%, respectively, of the total amount of gallons
we delivered. A continuing decline in the economy in these areas could
slow the rate of adoption of natural gas vehicles or impact the availability of
incentive funds, both of which could negatively impact our growth.
We provide financing to fleet customers for natural gas
vehicles, which exposes our business to credit risks.
We
loan to our customers up to 100% of the purchase price of natural gas
vehicles. We may also lease vehicles to customers in the future.
There are risks associated with providing financing or leasing that could cause
us to lose money. Some of these risks include: most of the equipment financed
is vehicles, which are mobile and easily damaged, lost or stolen; there is a
risk the borrower may default on payments; we may not be able to bill properly
or track payments in adequate fashion to sustain growth of this service; and
the amount of capital available to us is limited and may not allow us to make
loans required by customers. The continued disruption in the credit
markets may further reduce the amount of capital available to us and an
economic recession or slow down may increase the rate of default by borrowers,
leading to an increase in losses on our loan portfolio. As of September 30,
2008 we had $4.4 million outstanding in loans provided to customers to finance
natural gas vehicle purchases.
We may incur losses and use working capital if we are unable
to place with customers the natural gas vehicles that we or our business
partners order from manufacturers.
To
ensure availability for our customers, from time to time we enter into binding
purchase agreements for natural gas vehicles when there is a production lead
time. Although we attempt to arrange for customers to purchase the
vehicles before delivery to us, we may be unable to locate purchasers on a
timely basis and consequently may need to take delivery of and title to the vehicles.
These purchases would adversely affect our cash reserves until such time as we
can sell the vehicles to our customers, and we may be forced to sell the
vehicles at a loss. At September 30, 2008, we had $10.2 million of
deposits on vehicles under binding purchase agreements without corresponding
customer orders.
We
may also agree to guaranty the purchase of natural gas vehicles on behalf of
our business partners. For example, in July 2006, we entered into an
agreement with Inland Kenworth, Inc. (Inland) pursuant to which we agreed
to deposit certain amounts with Inland, as security for a guaranty, to help
fund the acquisition by Kenworth Truck Company (Kenworth) of up to 125 diesel
tractors. At September 30, 2008, we had outstanding $5.5 million
of deposits under this agreement. If any tractor purchased by Inland
remains unsold after a period of 365 days, we must either purchase the
tractor or instruct Inland to sell the tractor.
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We have advanced deposits to a business partner to help fund
the conversion of diesel tractors to run on LNG. To the extent any
converted tractor is not sold within 24 months of the date of the
applicable deposit agreement, we may forfeit the deposit related to such
vehicle.
We
entered into two deposit agreements with Westport in 2007 to facilitate the
production of LNG fuel systems for installation in the tractors purchased by
Inland. At September 30, 2008, we had outstanding a total of
$4.7 million to Westport under these agreements. Repayment of these
deposits will occur incrementally upon the sale of the converted tractors to
customers; however, to the extent an LNG fuel system incorporated into a
tractor is not sold within 24 months of the effective date of the
applicable deposit agreement (or such other time period as is agreed by both us
and Westport), Westport is not obligated to repay any of the deposit with
respect to such LNG fuel system.
There are many risks associated with conducting operations in
international markets.
We
are in the process of expanding our operations outside of the United States and
Canada. For example, in August 2007, we executed a joint venture agreement
with Energy Gas del Peru pursuant to which we built and operate a natural gas
fueling station in Lima, Peru. Changes in local economic or political
conditions in foreign countries could have a material adverse effect on our
business, consolidated financial condition, results of operations and cash
flows. Additional risks inherent in our international business activities
include the following: difficulties in managing international operations,
including our ability to timely and cost effectively execute projects;
unexpected changes in regulatory requirements; tariffs and other trade barriers
that may restrict our ability to enter into new markets; governmental actions
that result in the deprivation of contract rights; changes in political and
economic conditions in the countries in which we operate, including civil
uprisings, riots, kidnappings and terrorist acts; changes in foreign currency
exchange rates; potentially adverse tax consequences; restrictions on
repatriation of earnings or expropriation of property without fair
compensation; difficulties in establishing new international offices and risks
inherent in establishing new relationships in foreign countries; and the burden
of complying with the various laws and regulations in the countries in which we
operate.
Our
future plans may involve expanding our business in international markets where
we currently do not conduct business. The risks inherent in establishing
new business ventures, especially in international markets where local customs,
laws and business procedures present special challenges, may affect our ability
to be successful in these ventures or avoid losses which could have a material
adverse effect on our business, financial condition, results of operations and
cash flows.
Our business is subject to a variety of governmental
regulations that may restrict our business and may result in costs and
penalties.
We
are subject to a variety of federal, state and local laws and regulations
relating to the environment, health and safety, labor and employment and
taxation, among others. These laws and regulations are complex, change
frequently and have tended to become more stringent over time. Failure to
comply with these laws and regulations may result in a variety of administrative,
civil and criminal enforcement measures, including assessment of monetary
penalties and the imposition of remedial requirements. From time to time,
as part of the regular overall evaluation of our operations, including newly
acquired operations, we may be subject to compliance audits by regulatory
authorities.
In
connection with our LNG liquefaction activities or the landfill gas processing
facility operated by our subsidiary, Dallas Clean Energy, LLC, we need to apply
for additional facility permits or licenses to address storm water or
wastewater discharges, waste handling, and air emissions related to production
activities or equipment operations. This may subject us to permitting
conditions that may be onerous or costly. Compliance with laws and regulations
and enforcement policies by regulatory agencies could require us to make
material expenditures.
36
Table of Contents
which may distract our
officers, directors and employees from the operation of our business.
These efforts may not ultimately be effective to maintain adequate internal
controls. If we fail to establish and maintain effective controls and
procedures for financial reporting, we could be unable to provide timely and
accurate financial information. In addition, investor perceptions that
our internal controls are inadequate or that we are unable to produce accurate
financial statements may negatively affect our stock price.
Our quarterly results of operations have not been predictable
in the past and have fluctuated significantly and may not be predictable and
may fluctuate in the future.
Our
quarterly results of operations have historically experienced significant
fluctuations. Our net losses were $58.8 million, $14.6 million,
$0.9 million, $3.6 million, $1.5 million, $2.9 million,
$5.4 million and $2.4 million for the three months ended September 30,
2006, December 31, 2006, March 31, 2007, June 30, 2007, September 30,
2007, December 31, 2007, March 31, 2008 and June 30, 2008,
respectively. For the three-month period ended September 30, 2008,
we incurred a net loss of $18.5 million. Our quarterly results may
fluctuate significantly as a result of a variety of factors, many of which are
beyond our control. If our quarterly results of operations fall below the
expectations of securities analysts or investors, the price of our common stock
could decline substantially. Fluctuations in our quarterly results of
operations historically have primarily been attributable to our derivative
gains and losses, but also may be due to a number of other factors, including,
but not limited to: our ability to increase sales to existing customers and
attract new customers; the addition or loss of large customers; construction
cost overruns; the amount and timing of operating costs and capital
expenditures related to the maintenance and expansion of our business,
operations and infrastructure; changes in the price of natural gas; changes in
the prices of CNG and LNG relative to gasoline and diesel; changes in our
pricing policies or those of our competitors; the costs related to the
acquisition of assets or businesses; regulatory changes; and geopolitical
events such as war, threat of war or terrorist actions. Investors in our
stock should not rely on the results of one quarter as an indication of future
performance as our quarterly revenues and results of operations may vary
significantly in the future. Therefore, period-to-period comparisons of
our operating results may not be meaningful.
The price of our common stock may be volatile as a result of
market conditions unrelated to our company, and the value of your investment
could decline.
The
trading price of our common stock may fluctuate substantially due to factors in
the market beyond our control. These fluctuations could cause you to lose
all or part of your investment in our common stock. Factors that could
cause fluctuations in the trading price of our common stock include: price and
volume fluctuations in the overall stock market from time to time; actual or
anticipated changes or fluctuations in our results of operations; actual or
anticipated changes in the expectations of investors or securities analysts;
actual or anticipated developments in our competitors businesses or the
competitive landscape generally; litigation involving us or our industry;
domestic and international regulatory developments; general economic conditions
and trends; widespread adoption of other alternative fuels and technologies;
major catastrophic events or sales of large blocks of our stock. Since
our initial public offering, which was completed in May 2007, the price of
our common stock has ranged from an intra-day low of $8.06 to an intra-day high
of $20.65 through October 28, 2008.
Sales of outstanding shares of our stock into the market in
the future could cause the market price of our stock to drop significantly,
even if our business is doing well.
If
our existing stockholders sell, or indicate an intention to sell, substantial
amounts of our common stock in the public market, the trading price of our
common stock could decline. At September 30, 2008, 44,641,520 shares
of our common stock were outstanding. The 11,500,000 shares sold in our
initial public offering in addition to the 4,419,192 shares of common stock and
the shares of common stock subject to warrants sold in our offering closed November 3,
2008 are freely tradable without restriction or further registration under
federal securities laws unless purchased by our affiliates. Shares held
by non-affiliates for more than six months may generally be sold without
restriction, other than a current public information requirement, and may be
sold freely without any restrictions after one year. All other
outstanding shares of common stock may be sold under Rule 144 under the
Securities Act, subject to applicable restrictions.
In
addition, as of September 30, 2008, there were 7,018,955 shares underlying
outstanding options and 15,000,000 shares underlying an outstanding
warrant. In our offering of common stock and warrants that closed November 3,
2008, we issued Series I Warrants to purchase up to an aggregate of 3,314,394
shares of common stock, and Series II Warrants to purchase up to an aggregate
of 1,136,364 shares of common stock. On
November 12, 2008, all of the Series II Warrants had been excercised on a cashless
basis resulting in the issuance of 1,134,759 shares of our common stock to the Series
II Warrant holders. All shares subject
to outstanding options and warrants are eligible for sale in the public market
to the extent permitted by the provisions of various option and warrant
agreements and Rule 144. If these additional shares are sold, or if
it is perceived that they will be sold in the public market, the trading price
of our stock could decline.
37
Table of Contents
A majority of our stock is beneficially owned by a single
stockholder whose interests may differ from yours and who will be able to exert
significant influence over our corporate decisions, including a change of
control.
As
of September 30, 2008, Boone Pickens and affiliates (including Madeleine
Pickens, his wife) beneficially owned in the aggregate 58.9% of our outstanding
common stock, inclusive of the 15,000,000 shares underlying the warrant held by
Mr. Pickens. As a result, Mr. Pickens will be able to influence
or control matters requiring approval by our stockholders, including the
election of directors and the approval of mergers, acquisitions or other
extraordinary transactions. Mr. Pickens may also have interests that
differ from yours and may vote in a way with which you disagree and which may
be adverse to your interests. This concentration of ownership may have
the effect of delaying, preventing or deterring a change of control of our
company, could deprive our stockholders of an opportunity to receive a premium
for their stock as part of a sale of our company, and might ultimately affect
the market price of our stock. Conversely, this concentration may
facilitate a change in control at a time when you and other investors may
prefer not to sell.
38
Table of Contents
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, we incurred
additional costs of approximately $4.5 million of costs 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. 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, 2008, we have used the net proceeds from the offering as
follows:
·
construction
of our LNG liquefaction plant in California ($56.7 million),
·
construction
and installation of CNG and LNG stations ($18.2 million),
·
financing
customer vehicle purchases ($4.1 million), and
·
working
capital ($14.3 million).
The
balance of the proceeds has been from time to time invested in instruments that
have financial maturities no longer than six 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.
39
Table of
Contents
Item
5. Other Information
Sixth Amendment to Lease Agreement
On August 1,
2008, we and Clean Energy, our wholly-owned subsidiary, entered into a Sixth
Amendment to Lease Agreement with Bixbybit-Bixby Office Park, LLC, the
landlord, related to our executive offices located in Seal Beach, CA. Pursuant to the amendment:
·
We
relocated from certain premises, comprising approximately 16,881 square feet of
rentable space, on the second floor of 3020 Old Ranch Parkway, Seal Beach, CA
90740, to new premises, comprising approximately 19,881 rentable square feet of
space, on the fourth floor of such building.
·
Additional
premises subleased by us at our executive offices, which comprise an aggregate
of 11,196 square feet of rentable space, were made subject to the terms of the
lease agreement.
·
The
term of the lease agreement was extended to January 31, 2015.
·
The
aggregate monthly base rent for the full premises at our executive offices,
commencing on November 1, 2008, will be $66,344 per month for the first 12
months, and will increase for each subsequent 12 month period by specified
amounts, up to a maximum aggregate monthly base rent of $84,334 at the end of
the lease term.
·
We
paid the landlord $23,297 upon the signing of the amendment and an additional
$27,400 on November 1, 2008, the first day of the new lease term. Additionally, we made an additional security
deposit with the landlord of $48,690 upon the signing of the amendment.
A
complete copy of the amendment is attached as Exhibit 10.3 to this report
and is incorporated herein by reference. The summary of the transaction set
forth above does not purport to be complete and is qualified in its entirety by
reference to the amendment.
This
disclosure is provided in lieu of disclosure under Item 1.01 of Form 8-K.
First Amendment to Base Contract for Sale and
Purchase of Natural Gas and Guaranty
On November 7,
2008, Clean Energy, our wholly-owned subsidiary, entered into a First Amendment
to Base Contract for Sale and Purchase of Natural Gas with Shell Energy North
America (US), L.P., or Shell. Pursuant to the amendment, Clean Energy may
purchase natural gas on credit from Shell up to the lower of (i) $15.0
million, or (ii) the amount of any dollar limit contained in a guaranty
provided by us pursuant to the amendment, except that Clean Energy may not
purchase any natural gas on credit if a material adverse change or event of
default, in each case as defined in the amendment, has occurred and is
continuing.
In
connection with the amendment, on November 7, 2008, we executed a guaranty
in favor of Shell pursuant to which we agreed to guarantee the timely payment
when due of Clean Energys obligations to Shell under the base contract, as
amended. Our liability under the
guaranty will not exceed $15.0 million, plus reasonable attorneys fees and
expenses.
Complete
copies of the First Amendment to Base Contract for Sale and Purchase of Natural
Gas and the Guaranty are attached as Exhibits 10.4 and 10.5 to this report,
respectively, and are incorporated herein by reference. The summary of the
agreements described above does not purport to be complete and is qualified in
its entirety by reference to such agreements.
This
disclosure is provided in lieu of disclosure under Items 1.01 and 2.03 of Form 8-K.
40
Table
of Contents
Item
6. Exhibits
(a)
|
Exhibits
|
|
|
10.1
|
LNG
Sales Agreement dated July 1, 2008 between Williams Four Corners LLC and
the registrant.
+
|
|
|
10.2
|
Share Purchase Agreement dated September 5, 2008, among the
registrant, American Honda Motor Co., Inc., John G. Armstrong (sole
trustee of The FuelMaker Trust), and FuelMaker Corporation.
|
|
|
10.3
|
Sixth
Amendment to Lease Agreement
dated August 1, 2008 among the
registrant, Clean Energy and Bixbybit-Bixby Office Park, LLC.
|
|
|
10.4
|
First Amendment to Base Contract for Sale and Purchase of Natural Gas
dated November 7, 2008, between Clean Energy and Shell Energy North
America (US), L.P.
|
|
|
10.5
|
Guaranty dated November 7, 2008, executed by the registrant in
favor of Shell Energy North America (US), L.P.
|
|
|
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.
|
+
|
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 14, 2008
|
|
By:
|
/s/
|
Richard R. Wheeler
|
|
|
|
Richard R. Wheeler
|
|
|
|
Chief Financial Officer
(Principal financial officer and duly authorized
to sign on behalf of the registrant)
|
41
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