PART I.
FINANCIAL
INFORMATION
Item
1. Financial Statements (Unaudited)
Clean Energy Fuels Corp.
and Subsidiaries
Condensed Consolidated Balance Sheets
December 31, 2006 and September 30, 2007 (Unaudited)
|
|
December 31,
2006
|
|
September 30,
2007
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
937,445
|
|
$
|
74,769,017
|
|
Short-term investments
|
|
|
|
14,809,636
|
|
Accounts receivable, net of allowance for
doubtful accounts of $352,050 and $470,607 as of December 31, 2006 and September
30, 2007, respectively
|
|
10,997,328
|
|
10,579,361
|
|
Other receivables
|
|
37,818,905
|
|
16,715,379
|
|
Inventories, net
|
|
2,558,689
|
|
3,780,465
|
|
Prepaid expenses and other current assets
|
|
4,862,335
|
|
12,102,458
|
|
Total current assets
|
|
57,174,702
|
|
132,756,316
|
|
|
|
|
|
|
|
Land, property and equipment, net
|
|
54,888,739
|
|
80,471,904
|
|
Capital lease receivables
|
|
1,412,500
|
|
863,250
|
|
Notes receivable and other long term assets
|
|
2,499,106
|
|
13,741,968
|
|
Goodwill and other intangible assets
|
|
20,957,589
|
|
20,930,971
|
|
Total assets
|
|
$
|
136,932,636
|
|
$
|
248,764,409
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
Current portion of long term debt and
capital lease obligations
|
|
$
|
57,499
|
|
$
|
61,958
|
|
Accounts payable
|
|
6,697,363
|
|
7,875,906
|
|
Accrued liabilities
|
|
5,023,051
|
|
7,101,027
|
|
Deferred revenue
|
|
585,505
|
|
557,763
|
|
Total current liabilities
|
|
12,363,418
|
|
15,596,654
|
|
|
|
|
|
|
|
Long term debt and capital lease
obligations, less current portion
|
|
224,897
|
|
177,855
|
|
Other long term liabilities
|
|
1,428,464
|
|
1,361,912
|
|
Total liabilities
|
|
14,016,779
|
|
17,136,421
|
|
|
|
|
|
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders equity:
|
|
|
|
|
|
Preferred stock, par value $0.0001 per
share. 1,000,000 shares authorized; issued and outstanding, no shares
|
|
|
|
|
|
Common stock, par value $0.0001 per share.
99,000,000 shares authorized; issued and outstanding 34,192,161 shares and
44,210,245 shares at December 31, 2006 and September 30, 2007,
respectively
|
|
3,419
|
|
4,421
|
|
Additional paid-in capital
|
|
181,678,861
|
|
295,704,376
|
|
Accumulated deficit
|
|
(60,192,221
|
)
|
(66,170,272
|
)
|
Accumulated other comprehensive income
|
|
1,425,798
|
|
2,089,463
|
|
Total stockholders equity
|
|
122,915,857
|
|
231,627,988
|
|
Total liabilities and stockholders equity
|
|
$
|
136,932,636
|
|
$
|
248,764,409
|
|
See
accompanying notes to condensed consolidated financial statements.
2
Clean Energy Fuels Corp.
and Subsidiaries
Condensed Consolidated Statements of Operations
For the Three and Nine Months Ended
September 30, 2006 and 2007
(Unaudited)
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
|
|
2006
|
|
2007
|
|
2006
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
22,245,867
|
|
$
|
29,210,164
|
|
$
|
64,800,859
|
|
$
|
88,040,804
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
Cost of sales
|
|
18,237,804
|
|
20,252,744
|
|
54,933,048
|
|
64,100,466
|
|
Derivative losses
|
|
64,999,238
|
|
|
|
65,281,586
|
|
|
|
Selling, general and administrative
|
|
5,599,136
|
|
9,528,605
|
|
14,864,820
|
|
26,269,201
|
|
Depreciation and amortization
|
|
1,620,387
|
|
1,814,176
|
|
4,221,116
|
|
5,090,396
|
|
Total operating expenses
|
|
90,456,565
|
|
31,595,525
|
|
139,300,570
|
|
95,460,063
|
|
Operating loss
|
|
(68,210,698
|
)
|
(2,385,361
|
)
|
(74,499,711
|
)
|
(7,419,259
|
)
|
|
|
|
|
|
|
|
|
|
|
Interest income, net
|
|
(408,143
|
)
|
(1,414,120
|
)
|
(818,943
|
)
|
(2,253,083
|
)
|
Other expense, net
|
|
53,141
|
|
50,000
|
|
11,075
|
|
229,177
|
|
Loss before income taxes
|
|
(67,855,696
|
)
|
(1,021,241
|
)
|
(73,691,843
|
)
|
(5,395,353
|
)
|
Income tax expense (benefit)
|
|
(9,040,439
|
)
|
523,729
|
|
(10,773,775
|
)
|
582,698
|
|
Net loss
|
|
$
|
(58,815,257
|
)
|
$
|
(1,544,970
|
)
|
$
|
(62,918,068
|
)
|
$
|
(5,978,051
|
)
|
|
|
|
|
|
|
|
|
|
|
Loss per share
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(1.72
|
)
|
$
|
(0.03
|
)
|
$
|
(2.04
|
)
|
$
|
(0.15
|
)
|
Diluted
|
|
$
|
(1.72
|
)
|
$
|
(0.03
|
)
|
$
|
(2.04
|
)
|
$
|
(0.15
|
)
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding
|
|
|
|
|
|
|
|
|
|
Basic
|
|
34,179,961
|
|
44,195,339
|
|
30,829,470
|
|
38,919,129
|
|
Diluted
|
|
34,179,961
|
|
44,195,339
|
|
30,829,470
|
|
38,919,129
|
|
See
accompanying notes to condensed consolidated financial statements.
3
Clean Energy Fuels Corp.
Condensed Consolidated Statements of Cash Flows
For the Nine Months Ended September 30, 2006 and 2007
(Unaudited)
|
|
Nine Months Ended
September 30,
|
|
|
|
2006
|
|
2007
|
|
Cash flows from operating activities:
|
|
|
|
|
|
Net loss
|
|
$
|
(62,918,068
|
)
|
$
|
(5,978,051
|
)
|
Adjustments to reconcile net loss to net
cash provided by (used in) operating activities:
|
|
|
|
|
|
Depreciation and amortization
|
|
4,221,116
|
|
5,090,396
|
|
Provision for doubtful accounts
|
|
154,730
|
|
1,179,600
|
|
Unrealized loss on futures contracts
|
|
8,956,599
|
|
|
|
Loss on disposal of assets
|
|
|
|
178,674
|
|
Deferred income taxes
|
|
(10,773,775
|
)
|
|
|
Non-cash derivative contract loss
|
|
64,999,238
|
|
|
|
Stock option expense
|
|
|
|
5,425,443
|
|
Changes in operating assets and
liabilities:
|
|
|
|
|
|
Accounts and other receivables
|
|
(1,722,186
|
)
|
9,099,031
|
|
Inventories
|
|
(277,279
|
)
|
(1,221,776
|
)
|
Capital lease receivables
|
|
549,250
|
|
549,250
|
|
Margin deposits on futures contracts
|
|
(30,858,400
|
)
|
|
|
Prepaid expenses and other assets
|
|
(2,349,483
|
)
|
(9,436,235
|
)
|
Accounts payable
|
|
(1,434,466
|
)
|
1,269,128
|
|
Income taxes payable
|
|
(6,312,000
|
)
|
|
|
Accrued expenses and other
|
|
589,794
|
|
2,479,123
|
|
Net cash provided by (used in) operating
activities
|
|
(37,174,930
|
)
|
8,634,583
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
Purchases of property and equipment
|
|
(11,311,061
|
)
|
(30,252,537
|
)
|
Purchase of short-term investments
|
|
|
|
(14,809,636
|
)
|
Net cash used in investing activities
|
|
(11,311,061
|
)
|
(45,062,173
|
)
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
Repayment of notes payable and capital
lease obligations
|
|
(781,658
|
)
|
(42,583
|
)
|
Proceeds from exercise of stock options
|
|
8,880
|
|
79,142
|
|
Proceeds from issuance of common stock
|
|
21,951,788
|
|
110,222,603
|
|
Net cash provided by financing activities
|
|
21,179,010
|
|
110,259,162
|
|
|
|
|
|
|
|
Net increase (decrease) in cash
|
|
(27,306,981
|
)
|
73,831,572
|
|
Cash, beginning of period
|
|
28,763,445
|
|
937,445
|
|
Cash, end of period
|
|
$
|
1,456,464
|
|
$
|
74,769,017
|
|
|
|
|
|
|
|
Supplemental disclosure of cash flow
information
|
|
|
|
|
|
Income taxes paid
|
|
$
|
6,314,029
|
|
$
|
250
|
|
Interest paid
|
|
416,852
|
|
80,749
|
|
|
|
|
|
|
|
Non-cash financing activities:
|
|
|
|
|
|
Margin deposits directly advanced by
majority stockholder to broker under line of credit
|
|
$
|
31,055,000
|
|
$
|
|
|
See
accompanying notes to condensed consolidated financial statements.
4
CLEAN ENERGY FUELS CORP.
AND SUBSIDIARIES
NOTES TO CONDENSED
CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 General
Nature of Business:
Clean
Energy Fuels Corp. (the Company) is engaged in the business of providing
natural gas fueling solutions to its customers in the United States and Canada.
The Company has a broad customer base in a variety of markets including public
transit, refuse, airports and regional trucking. Clean Energy operates over 170
fueling locations principally in California, Texas, Colorado, Maryland, New
York, New Mexico, Washington, Massachusetts, Georgia, and Arizona within the
United States, and in British Columbia and Ontario within Canada.
Basis of Presentation:
The
accompanying interim unaudited condensed consolidated financial statements
include the accounts of the Company and its subsidiaries, and, in the opinion
of management, reflect all adjustments, which include only normal recurring
adjustments, necessary to state fairly the Companys financial position, results
of operations and cash flows for the three and nine months ended September 30,
2006 and 2007. All intercompany accounts and transactions have been eliminated
in consolidation. The three and nine month periods ended September 30, 2006 and
2007 are not necessarily indicative of the results to be expected for the year
ending December 31, 2007 or for any other interim period or for any future
year.
Certain
information and disclosures normally included in the notes to consolidated
financial statements have been condensed or omitted pursuant to the rules and
regulations of the Securities and Exchange Commission (SEC), but the
resultant disclosures contained herein are in accordance with accounting
principles generally accepted in the United States of America as they apply to
interim reporting. The condensed consolidated financial statements should be
read in conjunction with the consolidated financial statements as of and for
the year ended December 31, 2006 that are included in the Companys Form S-1
filed with the SEC.
Note 2
Cash
and Cash Equivalents
The
Company considers all highly liquid investments with maturities of three months
or less on the date of acquisition to be cash equivalents. Cash and cash
equivalents generally consist of cash, time deposits, commercial paper, money
market funds and government and corporate debt securities with original
maturity dates of three months or less. Such investments are stated at cost,
which approximates fair value.
Note 3
Short-Term
Investments
Short-term investments, which are classified as available for sale,
generally consist of commercial paper and government and commercial debt
securities with original maturity dates between three and six months. Short-term
investments are marked-to-market at each period end with any unrealized gains
or losses included in the condensed consolidated balance sheets under the line
item accumulated other comprehensive income.
Note 4
Derivative Financial Instruments
The
Company, in an effort to manage its natural gas commodity price risk exposures,
utilizes derivative financial instruments. The Company often enters into
natural gas futures contracts that are over-the-counter swap transactions that
convert its index-based gas supply arrangements to fixed-price arrangements.
The Company accounts for its derivative instruments in accordance with SFAS
No. 133,
Accounting for Derivative
Instruments and Hedging Activities
, as amended. SFAS 133
requires the recognition of all derivatives as either assets or liabilities in
the consolidated balance sheet and the measurement of those instruments at fair
value. The Companys derivative instruments did not qualify for hedge
accounting under SFAS 133 for the year ended December 31, 2006. As
such, changes in the fair value of the derivatives were recorded directly to
the consolidated statements of operations during the year. The Company did not
have any futures contracts outstanding during the three or nine month periods
ended September 30, 2007.
The Company marks to market its open futures position at the end of
each period and records the net unrealized gain or loss during the period in
derivative (gains) losses in the accompanying condensed consolidated statements
of operations. For the nine month periods ended September 30, 2006 and 2007,
the Companys unrealized net loss amount totaled $73,955,837
and
$0, respectively.
5
The
Company is required to make certain deposits on its futures contracts, should
any exist. At December 31, 2006 and September 30, 2007, the Company did
not have any deposits outstanding as it did not have any futures contracts
outstanding at the end of these periods.
During
the nine months ended September 30, 2006 and 2007, the Company recognized
realized gains of $8,674,251 and $0, respectively, related to the sales of
futures contracts.
Note 5
Fixed Price and Price Cap Sales Contracts
The
Company has entered into contracts with various customers, primarily
municipalities, to sell liquefied natural gas (LNG) or compressed natural gas
(CNG) at fixed prices or at prices subject to a price cap. As of January 1,
2007, the Company no longer intends to enter into price cap contracts. The
contracts generally range from two to five years. The most significant cost
component of LNG and CNG is the price of natural gas.
As
part of determining the fixed price or price cap in the contracts, the Company
works with its customers to determine their future usage over the contract
term. However, the 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 4) and, if the Company believed the price of natural gas would decline in
the future, periodically sold such contracts.
From
an accounting perspective, during periods of rising natural gas prices, the
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).
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, 2007:
|
|
Estimated
volumes (a)
|
|
Average
price (b)
|
|
Contracts
duration
|
|
CNG fixed price contracts
|
|
1,490,621
|
|
$
|
1.13
|
|
through 12/13
|
|
LNG fixed price contracts
|
|
17,210,187
|
|
$
|
.38
|
|
through 7/09
|
|
CNG price cap contracts
|
|
5,027,520
|
|
$
|
.86
|
|
through 12/09
|
|
LNG price cap contracts
|
|
9,663,782
|
|
$
|
.56
|
|
through 12/08
|
|
(a)
Estimated volumes are
in gasoline gallon equivalents for CNG contracts and are in LNG gallons for LNG
contracts and represent the volumes the Company anticipates delivering over the
remaining duration of the contracts.
(b)
Average prices are in
gasoline gallon equivalents for CNG contracts and are in LNG gallons for LNG
contracts. The average prices represent the natural gas commodity component
embedded in the customers contract.
6
At
September 30, 2007, based on natural gas futures prices as of that date, the
Company estimates it will incur between $5.0 million and $6.2 million to
cover the increased price of natural gas above the inherent price of natural
gas embedded in its 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, 2007, and these estimates may change based on future
natural gas prices and may be significantly higher or lower. The Companys
volumes under these contracts, in gasoline gallon equivalents, expire as
follows:
October 1, 2007 through
December 31, 2007
|
|
5,490,150
|
|
2008
|
|
15,250,419
|
|
2009
|
|
2,486,896
|
|
2010
|
|
230,000
|
|
2011
|
|
230,000
|
|
2012
|
|
230,000
|
|
2013
|
|
230,000
|
|
Note 6 Other
Receivables
Other
receivables at December 31, 2006 and September 30, 2007 consisted of the
following:
|
|
December 31,
2006
|
|
September 30,
2007
|
|
|
|
|
|
|
|
Loans to customers to finance vehicle
purchases
|
|
$
|
816,837
|
|
$
|
1,342,671
|
|
Advances to vehicle manufacturers
|
|
2,465,776
|
|
4,436,706
|
|
Fuel tax credits
|
|
3,810,109
|
|
4,016,766
|
|
Futures contracts deposit receivable
|
|
22,900,000
|
|
|
|
Income tax receivable
|
|
5,600,071
|
|
5,017,623,
|
|
Other
|
|
2,226,112
|
|
1,901,613
|
|
|
|
$
|
37,818,905
|
|
$
|
16,715,379
|
|
Note 7 Land,
Property and Equipment
Land,
property and equipment, at cost, at December 31, 2006 and September 30,
2007 are summarized as follows:
|
|
December 31,
2006
|
|
September 30,
2007
|
|
Land
|
|
$
|
472,616
|
|
$
|
472,616
|
|
LNG liquefaction plant
|
|
12,898,178
|
|
12,898,178
|
|
Station equipment
|
|
36,913,552
|
|
42,967,572
|
|
LNG tanker trailers
|
|
8,253,415
|
|
11,865,380
|
|
Other equipment
|
|
6,144,553
|
|
6,611,031
|
|
Construction in progress
|
|
7,304,612
|
|
27,986,367
|
|
|
|
71,986,926
|
|
102,801,144
|
|
Less accumulated depreciation
|
|
(17,098,187
|
)
|
(22,329,240
|
)
|
|
|
$
|
54,888,739
|
|
$
|
80,471,904
|
|
Note 8 Accrued
Liabilities
Accrued
liabilities at December 31, 2006 and September 30, 2007 consisted of the
following:
|
|
December 31,
2006
|
|
September 30,
2007
|
|
Salaries and wages
|
|
$
|
1,286,196
|
|
$
|
2,635,467
|
|
Accrued gas purchases
|
|
1,566,847
|
|
2,376,895
|
|
Other
|
|
2,170,008
|
|
2,088,665
|
|
|
|
$
|
5,023,051
|
|
$
|
7,101,027
|
|
7
Note 9 Earnings
Per Share
Basic
earnings per share is based upon the weighted average number of shares
outstanding during each period. Diluted earnings per share reflects the impact
of assumed exercise of dilutive stock options and warrants. The information
required to compute basic and diluted earnings per share is as follows:
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
|
|
2006
|
|
2007
|
|
2006
|
|
2007
|
|
Basic and diluted:
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares
outstanding
|
|
34,179,961
|
|
44,195,339
|
|
30,829,470
|
|
38,919,129
|
|
Certain
securities were excluded from the diluted earnings per share calculations at
September 30, 2006 and 2007, respectively, as the inclusion of the securities
would be anti-dilutive to the calculation. The amounts outstanding as of
September 30, 2006 and 2007 for these instruments are as follows:
|
|
September 30,
|
|
|
|
2006
|
|
2007
|
|
|
|
|
|
|
|
Options
|
|
2,414,750
|
|
5,720,666
|
|
Warrants
|
|
|
|
15,000,000
|
|
Note 10
Comprehensive Income
The
following table presents the Companys comprehensive income for the nine months
ended September 30, 2006 and 2007:
|
|
Nine Months Ended
September 30,
|
|
|
|
2006
|
|
2007
|
|
Net loss
|
|
$
|
(62,918,068
|
)
|
$
|
(5,978,051
|
)
|
Foreign currency translation adjustments
|
|
275,272
|
|
663,665
|
|
|
|
|
|
|
|
Comprehensive loss
|
|
$
|
(62,642,796
|
)
|
$
|
(5,314,386
|
)
|
Note 11 Stock
Based Compensation
The following table summarizes the compensation
expense and related income tax benefit related to share
-
based
compensation expense recognized during the periods:
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
|
|
2006
|
|
2007
|
|
2006
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
Stock options
|
|
|
|
|
|
|
|
|
|
Share-based compensation expense
|
|
$
|
|
|
$
|
1,592,789
|
|
$
|
|
|
$
|
5,425,443
|
|
Income tax benefit
|
|
|
|
|
|
|
|
|
|
Share-based compensation expense, net of
tax
|
|
$
|
|
|
$
|
1,592,789
|
|
$
|
|
|
$
|
5,425,443
|
|
8
Stock
Options
The
following table summarizes all stock option activity during the nine months
ended September 30, 2007:
|
|
Number
of
Shares
|
|
Weighted-
Average
Exercise
Price
|
|
|
|
|
|
|
|
Outstanding at December 31, 2006
|
|
2,402,250
|
|
$
|
2.97
|
|
Granted
|
|
3,337,500
|
|
12.17
|
|
Exercised
|
|
(18,084
|
)
|
4.38
|
|
Cancelled/Forfeited
|
|
(1,000
|
)
|
12.00
|
|
Outstanding at September 30, 2007
|
|
5,720,666
|
|
8.36
|
|
|
|
|
|
|
|
Exercisable at September 30, 2007
|
|
2,848,833
|
|
4.43
|
|
|
|
|
|
|
|
|
The fair value of each option grant is estimated on the
date of grant using the Black-Scholes option pricing model with the following
weighted average assumptions used for grants in 2007:
|
|
Nine Months Ended
September 30,
2007
|
|
|
|
|
|
Dividend yield
|
|
0.00
|
%
|
Expected volatility
|
|
55.00
|
%
|
Risk-free interest rate
|
|
4.81
|
%
|
Expected life in years
|
|
5.75
|
|
The weighted average grant date fair value of options
granted using these assumptions was $6.81 for the nine months ended September
30, 2007.
Note 12 Use of
Estimates
The
preparation of consolidated financial statements in conformity with U.S.
generally accepted accounting principles require management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
the disclosure of contingent assets and liabilities at the date of the
consolidated financial statements and revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Note 13
Environmental Matters, Litigation, Claims, Commitments and Contingencies
The
Company is subject to federal, state, local, and foreign environmental laws and
regulations. The Company does not anticipate any expenditures to comply with
such laws and regulations which would have a material impact on the 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, 2007, the Company had entered into
purchase commitments totaling $33.0 million related to constructing its LNG
liquefaction plant in California, of which $16.8 million had been paid as of
this date.
9
Note
14 Income Taxes
In June 2006, the FASB issued FASB Interpretation
(FIN) No. 48, Accounting for Uncertainty in Income Taxes, an
interpretation of FASB Statement No. 109. This interpretation specifies
that benefits from tax positions should be recognized in the financial
statements only when it is more-likely-than-not that the tax position will be
sustained upon examination by the appropriate taxing authority having full
knowledge of all relevant information. A tax position meeting the
more-likely-than-not recognition threshold should be measured at the largest
amount of benefit for which the likelihood of realization upon ultimate
settlement exceeds 50 percent.
The Company adopted the provisions of FIN 48 on
January 1, 2007. On December 31, 2006 and September 30, 2007, the
Companys liabilities for uncertain tax positions were not significant.
The
Companys policy is to recognize interest and penalties related to liabilities
for uncertain tax benefits in the provisions for income and other taxes on the
consolidated condensed statements of income. The net interest and penalties
incurred were immaterial for the three and nine months ended September 30, 2006
and 2007.
The
Company is subject to audit by tax authorities for varying periods in various
tax jurisdictions. Taxable years from 2002 and 2003, respectively, are subject
to audit for state and U.S. federal corporate income tax purposes. The Company
is currently under audit by the State of California for tax years 2004 and
2005. Disputes may arise during the course of such audits as to facts and matters
of law.
During
June 2007, the Company requested permission from the Internal Revenue Service
to change its method of accounting for its derivative gains and losses related
to futures contracts that are sold in one period but relate to a subsequent period.
On July 5, 2007, the Internal Revenue Service granted the Companys request. The
Company began reporting the income tax impact of the change in the third
quarter of 2007. The Company anticipates that the adoption of the new method
will create a federal and state alternative minimum tax liability in the amount
of $825,000 for 2007, which liability will generate a corresponding alternative
minimum tax credit in the same amount which can be carried forward indefinitely
to offset future regular income tax liability in excess of the tentative
minimum tax.
Note
15 Subsequent Event
On
October 17, 2007, the Company entered into an LNG sales agreement with Spectrum
Energy Services, LLC (SES), to purchase, on a take-or-pay basis over a term of
10 years, 45,000 gallons per day of LNG from a plant to be constructed by SES
in Ehrenberg, Arizona, which is near the California border.
Item
2. Managements Discussion and Analysis of Financial Condition and Results of
Operations.
The
discussion in this section contains forward-looking statements. These
statements relate to future events or our future financial performance. We have
attempted to identify forward-looking statements by terminology such as anticipate,
believe, can, continue, could, estimate, expect, intend, may, plan,
potential, predict, should, would or will or the negative of these
terms or other comparable terminology. These statements are only predictions
and involve known and unknown risks, uncertainties and other factors, which
could cause our actual results to differ from those projected in any
forward-looking statements we make. See Risk Factors in Part II, Item 1A of
this report for a discussion of some of these risks and uncertainties. This
discussion should be read with our financial statements and related notes
included elsewhere in this report.
We
provide natural gas solutions for vehicle fleets in the United States and
Canada. Our primary business activity is supplying CNG and LNG vehicle fuels to
our customers. We also build, operate and maintain fueling stations, and help
our customers acquire and finance natural gas vehicles and obtain local, state
and federal clean air incentives. Our customers include fleet operators in a
variety of markets, such as public transit, refuse hauling, airports, taxis and
regional trucking.
Overview
This overview discusses matters on which our management
primarily focuses in evaluating our financial condition and operating
performance.
Sources of revenue
.
We generate the vast majority of our revenue from supplying CNG and LNG to our
customers. The balance of our revenue is provided by operating and maintaining
natural gas fueling stations, designing and constructing natural gas fueling
stations, and financing our customers natural gas vehicle purchases.
10
Key operating data
.
In evaluating our operating performance, our management focuses primarily on
(1) the amount of CNG and LNG gasoline gallon equivalents delivered and (2) our
revenue and net income (loss). The following table, which you should read in
conjunction with our financial statements and notes contained elsewhere in this
report, presents our key operating data for the years ended December 31, 2004,
2005 and 2006 and for the three and nine months ended September 30, 2006 and
2007:
Gasoline gallon equivalents
delivered (in millions)
|
|
Year ended
December 31,
2004
|
|
Year ended
December 31,
2005
|
|
Year ended
December 31,
2006
|
|
Three months
ended
September 30,
2006
|
|
Nine months
ended
September 30,
2006
|
|
Three months
ended
September 30,
2007
|
|
Nine months
ended
September 30,
2007
|
|
CNG
|
|
30.6
|
|
36.1
|
|
41.9
|
|
11.3
|
|
31.0
|
|
12.9
|
|
36.3
|
|
LNG
|
|
15.7
|
|
20.7
|
|
26.5
|
|
6.9
|
|
19.7
|
|
7.1
|
|
20.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
46.3
|
|
56.8
|
|
68.4
|
|
18.2
|
|
50.7
|
|
20.0
|
|
57.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
57,641,605
|
|
$
|
77,955,083
|
|
$
|
91,547,316
|
|
$
|
22,245,867
|
|
$
|
64,800,859
|
|
$
|
29,210,164
|
|
$
|
88,040,804
|
|
Net income (loss)
|
|
2,129,241
|
|
17,257,587
|
|
(77,500,741
|
)
|
(58,815,257
|
)
|
(62,918,068
|
)
|
(1,544,970
|
)
|
(5,978,051
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Key
trends in 2004, 2005, 2006 and the first nine months of 2007
.
Vehicle fleet demand for natural gas fuels increased significantly from
January 1, 2004 through the first nine months of 2007. This growth in
demand was attributable primarily to the rising prices of gasoline and diesel
relative to CNG and LNG during these periods and increasingly stringent
environmental regulations affecting vehicle fleets. We capitalized on this
growing demand by securing new fleet customers in a variety of markets,
including public transit, refuse hauling, airports, taxis and regional
trucking. Sales to previously existing customers also increased during these
periods as they expanded their fleets.
The
annual amount of CNG and LNG gasoline gallon equivalents we delivered increased
by 48% from 2004 to 2006. The amount of CNG and LNG gasoline gallon equivalents
we delivered from the first nine months of 2006 to the first nine months of
2007 increased by 13%. The increase in gasoline gallon equivalents delivered,
together with generally higher prices we charged our customers due to higher
natural gas prices, contributed to increased revenues during these periods. Our
cost of sales also increased during these periods, which was attributable
primarily to increased costs related to delivering more CNG and LNG to our
customers and the increased price of natural gas.
Anticipated
future trends
. We anticipate that, over the long term, the
prices for gasoline and diesel will continue to be higher than the price of
natural gas as a vehicle fuel, and more stringent emissions requirements will
continue to make traditional gasoline and diesel powered vehicles more
expensive for vehicle fleets. We believe there will be significant growth in
the consumption of natural gas as a vehicle fuel generally, and our goal is to
capitalize on this trend and enhance our leadership position as this market
expands. We recently began focusing on the seaports market. We are in the
process of building a natural gas fueling station, and plan to build additional
natural gas fueling stations that service the Ports of Los Angeles and Long
Beach. We also anticipate expanding our sales of CNG and LNG in the other
markets in which we operate, including public transit, refuse hauling and
airport markets. Consistent with the anticipated growth of our business, we
also expect that our operating costs will increase, primarily from the
logistics of delivering more CNG and LNG to our customers, as well as from the
anticipated expansion of our station network. We also plan to incur significant
costs related to the LNG liquefaction plant we are in the initial stages of
building in California. Additionally, we intend to increase our sales and
marketing team as we seek to expand our existing markets and enter new markets,
which will also result in increased costs.
Sources
of liquidity and anticipated capital expenditures
. In May
2007, we completed our initial public offering of 10,000,000 shares of common
stock at a public offering price of $12.00 per share. Net cash proceeds from
the initial public offering were approximately $108.5 million, after deducting
underwriting discounts, commissions and offering expenses. Historically, our
principal sources of liquidity have been cash provided by operations, capital
contributions from our stockholders, our cash and cash equivalents and, during
the third and fourth quarters of fiscal 2006, a revolving line of credit with
Boone Pickens, a director and our largest stockholder. The line of credit was
used to fund margin requirements on certain derivative contracts and was
terminated in December 2006. In 2007, we expect to spend our cash primarily on
building an LNG liquefaction plant in California, constructing new fueling stations,
purchasing new LNG tanker trailers, financing natural gas vehicle purchases by
our customers and for general corporate purposes, including making deposits to
support our derivative activities, geographic expansion (domestically and
internationally), expanding our sales and marketing activities, and for working
capital for our expansion. For more information, see Liquidity and Capital
Resources below.
11
Volatility
in operating results related to futures contracts
. Historically,
we have purchased futures contracts from time to time to help mitigate our
exposure to natural gas price fluctuations in current periods and in future
periods. Gains and losses related to our futures activities, which appear in the
line item derivative (gains) losses in our consolidated financial statements,
have materially impacted our results of operations in recent periods. For the
years ended December 31, 2004, 2005 and 2006 derivative (gains) losses were
$(10,572,349), $(44,067,744), and $78,994,947, respectively. For the nine month
periods ended September 30, 2006 and 2007, derivative losses were $65,281,586
and $0, respectively. For this reason and others, we caution investors that our
past operating results may not be indicative of future results. For more
information, see Volatility of Earnings and Cash Flows and Risk Management
Activities below.
Business
risks and uncertainties
. Our business and prospects are
exposed to numerous risks and uncertainties. For more information, see Risk
Factors in Part II, Item 1A of this report.
Operations
We
generate revenues principally by selling CNG and LNG to our vehicle fleet
customers. For the nine months ended September 30, 2007, CNG represented 63%
and LNG represented 37% of our natural gas sales (on a gasoline gallon
equivalent basis). To a lesser extent, we generate revenues by operating and
maintaining natural gas fueling stations that are owned either by us or our
customers. Substantially all of our operating and maintenance revenues are
generated from CNG stations, as owners of LNG stations tend to operate and
maintain their own stations. In addition, we generate a small portion of our
revenues by designing and constructing fueling stations and selling or leasing
those stations to our customers. Substantially all of our station sale and
leasing revenues have been generated from CNG stations. In 2006, we also began
providing vehicle finance services to our customers.
CNG Sales
We
sell CNG through fueling stations located on our customers properties and
through our network of public access fueling stations. At these CNG fueling
stations, we procure natural gas from local utilities or brokers under
standard, floating-rate arrangements and then compress and dispense it into our
customers vehicles. Our CNG sales are made primarily through contracts with
our fleet customers. Under these contracts, pricing is determined primarily on
an index-plus basis, which is calculated by adding a margin to the local index
or utility price for natural gas. We sell a small amount of CNG under
fixed-price contracts and also provide price caps to certain customers on their
index-plus pricing arrangement. We no longer intend to offer price-cap
contracts to our customers, but we will continue to perform our obligations
under price-cap contracts we entered into before January 1, 2007. Our
fleet customers typically are billed monthly based on the volume of CNG sold at
a station. A smaller portion of our CNG sales are on a per fill-up basis at
prices we set at the pump based on prevailing market conditions. These
customers typically pay using a credit card at the station.
LNG Sales
We
sell substantially all of our LNG to fleet customers, who typically own and
operate their fueling stations. We also sell a small volume of LNG to customers
for non-vehicle use. We procure LNG from third-party producers and also produce
LNG at our liquefaction plant in Texas. For LNG that we purchase from
third-parties, we typically enter into take or pay contracts that require us
to purchase minimum volumes of LNG at index-based rates. We deliver LNG via our
fleet of 60 tanker trailers to fueling stations, where it is stored and
dispensed in liquid form into vehicles. We sell LNG principally through supply
contracts that are priced on either a fixed-price or index-plus basis. We also
provided price caps to certain customers on the index component of their
index-plus pricing arrangement for certain contracts we entered into on or
before December 31, 2006. We no longer intend to offer price-cap contracts to
our customers, but we will continue to perform our obligations under price-cap
contracts we entered into before January 1, 2007. Our LNG contracts
provide that we charge our customers periodically based on the volume of LNG
supplied.
Government Incentives
From
October 1, 2006 through September 30, 2009, we may receive a
Volumetric Excise Tax Credit (VETC) of $0.50 per gasoline gallon equivalent of
CNG and $0.50 per liquid gallon of LNG that we sell as vehicle fuel. Based on
the service relationship we have with our customers, either we or our customers
are able to claim the credit. We expect the tax credit will continue to factor
into the price we charge our customers for CNG and LNG in the future. The
legislation that created this tax credit also increased the federal excise
taxes on sales of CNG from $0.061 to $0.183 per gasoline gallon equivalent and
on sales of LNG from $0.119 to $0.243 per LNG gallon. These new excise tax
rates are approximately the same as those for gasoline and diesel fuel.
12
The
Internal Revenue Service has not issued final guidance concerning VETC as it
relates to LNG sales to tax-exempt entities. Consequently, we have not recorded
any benefit of VETC related to these sales in our consolidated financial
statements for contracts entered into prior to October 1, 2006.
Operation and Maintenance
We
generate a smaller portion of our revenue from operation and maintenance
agreements for CNG fueling stations where we do not supply the fuel. We refer
to this portion of our business as O&M. At these fueling stations, the
customer contracts directly with a local broker or utility to purchase natural
gas. For O&M services, we do not sell the fuel itself, but generally charge
a per-gallon fee based on the volume of fuel dispensed at the station.
Station Construction
We
generate a small portion of our revenue from designing and constructing fueling
stations and selling or leasing the stations to our customers. For these
projects, we act as general contractor or supervise qualified third-party
contractors. We charge construction fees or lease rates based on the size and
complexity of the project.
Vehicle Acquisition and
Finance
In
2006, we commenced offering vehicle finance services for some of our customers
purchases of natural gas vehicles or the conversion of their existing gasoline
or diesel powered vehicles to operate on natural gas. Through these services,
we loan to our customers up to 100% of the purchase price of their natural gas
vehicles. We may also lease vehicles in the future. Where appropriate, we apply
for and receive state and federal incentives associated with natural gas
vehicle purchases and pass these benefits through to our customers. We may also
secure vehicles to place with customers prior to receiving a firm order from
our customers, which we may be required to purchase if our customer fails to
purchase the vehicle as anticipated. For the nine month period ended September
30, 2007, we generated $0.2 million of revenue from vehicle finance activities.
Volatility of
Earnings and Cash Flows
Our
earnings and cash flows historically have fluctuated significantly from period
to period based on our futures activities, as our futures contracts to date
have not qualified for hedge accounting under SFAS 133. See Critical
Accounting PoliciesDerivative Activities below. We have therefore recorded
any changes in the fair market value of these contracts directly in our
statements of operations in the line item derivative (gains) losses along with
any realized gains or losses generated during the period. For example, we
experienced derivative gains of $33.1 million for the three months ended
September 30, 2005 and experienced derivative losses of
$19.9 million, $0.3 million, $65.0 million and
$13.7 million for the three months ended December 31, 2005,
March 31, 2006, September 30, 2006 and December 31, 2006,
respectively. We had no derivative gains or losses for the three months ended
June 30, 2006, March 31, 2007, June 30, 2007 and September 30, 2007. Commencing
with the adoption of our revised natural gas hedging policy in
February 2007, we plan to structure all subsequent futures contracts as
cash flow hedges under SFAS 133, but we cannot be certain that they will
qualify. See Risk Management Activities below. If the futures contracts do
not qualify for hedge accounting, we could incur significant increases or
decreases in our earnings based on fluctuations in the market value of these
contracts from period to period.
Additionally,
we are required to maintain a margin account to cover losses related to our
natural gas futures contacts. Futures contracts are valued daily, and if our
contracts are in loss positions at the end of a trading day, our broker will
transfer the amount of the losses from our margin account to a clearinghouse.
If at any time the funds in our margin account drop below a specified
maintenance level, our broker will issue a margin call that requires us to
restore the balance. Consequently, these payments could significantly impact
our cash balances.
The
decrease in the value of our futures positions and any required margin deposits
on our futures contracts that are in a loss position could significantly impact
our financial condition in the future. At September 30, 2007, we had no futures
contracts outstanding and no amounts on deposit.
13
Risk Management
Activities
A
significant portion of our natural gas fuel sales are covered by contracts to
sell LNG or CNG to our customers at a fixed price or a variable index-based
price subject to a cap. These contracts expose us to the risk that the price of
natural gas may increase above the natural gas cost component included in the
price at which we are committed to sell gas to our customers. We account for
sales of natural gas under these contracts as described below in Critical
Accounting PoliciesFixed Price and Price Cap Sales Contracts.
Risk Management Practices
Before February 2007
Historically,
when we entered into a contract to sell natural gas fuel to a customer at a
fixed price or a variable price subject to a cap, we generally sought to manage
our exposure to natural gas price increases for some or all of the expected contract
volumes in the natural gas futures market. We did this by purchasing futures
contracts that were designed to cover the difference between the commodity
portion of the price at which we were committed to sell natural gas and the
price we had to pay for gas at delivery, thereby fixing the cost of natural gas
we were paying. We generally purchased futures contracts covering all or a
portion of our anticipated volumes in future periods.
From
time to time, if we believed natural gas prices would decline in the future, we
periodically elected to terminate futures contracts associated with fixed price
or price cap customer contracts by selling the futures contracts and
recognizing a gain upon such sales. When we did so, we lost future economic
protections provided by the futures contracts.
From
2003 through 2005, we sold futures contracts covering estimated sales volumes
over future periods and realized a net gain of approximately $44.8 million
upon the sale of these contracts. In 2006, we disposed of certain futures
contracts covering estimated sales volumes over future periods and realized a
net loss of $78.7 million.
Our
derivative activities are reflected in the line item derivative (gains) losses
in our consolidated statements of operations. Two components make up this line
item: (1) realized (gains) losses, and (2) unrealized (gains) losses.
Realized (gains) losses represent the actual (gains) losses we realize when we
sell or settle a futures contract during a period. Unrealized (gains) losses
represent the (gain) or loss we record at the end of each period when we mark
to market our open futures contracts at the end of each period. For realized
(gains) losses on contracts sold or settled during a period, there is typically
a corresponding unrealized loss (gain) on the contracts since the contracts are
no longer outstanding at the end of the period and are therefore marked to
zero.
We
have a derivative committee of our board of directors and have historically
conducted our futures contract activity under the advice of BP Capital L.P. (BP
Capital), an entity of which Boone Pickens, our largest stockholder and a
director, is the principal. Through December 31, 2006, we paid BP Capital
a monthly fee of $10,000 and a commission equal to 20% of our realized gains,
net of realized losses, during a calendar year relating to the purchase and
sale of natural gas futures contracts. BP Capital remitted realized net gains
to us, less its applicable commissions, on a monthly basis. We paid fees to BP
Capital of $0.4 million in 2004, $11.7 million in 2005,
$2.4 million in 2006, and $0 during the first three months of 2007. In
March 2007, we amended our agreement with BP Capital to remove the 20%
commission on our realized net gains during a calendar year.
We
historically have purchased our natural gas futures contracts from Sempra
Energy Trading Corp (Sempra). The futures are based on the Henry Hub natural
gas price set on the New York Mercantile Exchange. One futures contract for CNG
covers approximately 80,000 gasoline gallon equivalents of CNG, and one futures
contract for LNG covers approximately 120,000 gallons of LNG. Each contract had
historically required a deposit from us of $1,000, which is below market due to
the fact that Boone Pickens had guaranteed our futures obligations to Sempra.
Without this guarantee, which was cancelled March 7, 2007, we estimate the
deposit amount rate will be approximately $5,000 to $12,000 per contract
depending on market conditions. Additionally, without this guaranty, Sempra may
terminate our contract. As of September 30, 2007, we had no futures contracts
outstanding and no amounts on deposit.
August 2006 Purchase of
Futures Contracts and December 2006 Assumption by Boone Pickens
On
August 2, 2006, we purchased the following futures contracts and made
related deposits of $9.5 million:
Futures settlement year
|
|
Volume covered by futures
(gasoline gallon equivalents)
|
|
2008
|
|
161,300,000
|
|
2009
|
|
201,625,000
|
|
2010
|
|
201,625,000
|
|
2011
|
|
201,625,000
|
|
14
In
December 2006, Mr. Pickens assumed all of these futures contracts,
together with any and all associated liabilities and obligations, in exchange
for (1) the issuance to Mr. Pickens of a five-year warrant to
purchase up to 15,000,000 shares of our common stock at a purchase price of
$10.00 per share (which warrant was valued at $80.9 million), and (2) the
assignment to Mr. Pickens of any refunds of margin deposits related to the
assumed futures contracts that were made using money borrowed under the line of
credit with Mr. Pickens. At the time of assumption, these futures contracts had
lost $78.7 million in value. The difference between the value of the
warrant and the value of the losses on the futures contracts
($2.2 million) was recorded in our statement of operations as a loss on
extinguishment of derivative liability. This warrant will be dilutive to net
income per share if the fair market value of our common stock exceeds $10 per
share in the future.
Adoption of Revised Natural
Gas Hedging Policy in February 2007
In an
effort to mitigate the volatility of our earnings related to our futures
contracts and to reduce our risk related to fixed-price sales contracts, our
board of directors revisited our risk management policies and procedures and
adopted a revised natural gas hedging policy which restricts our ability to
purchase natural gas futures contracts and offer fixed-price sales contracts to
our customers. Unless otherwise agreed in advance by the board of directors and
the derivative committee, we will conduct our futures activities and offer of
fixed-price sales contracts pursuant to the policy as follows:
1.
We may purchase
futures contracts only to hedge our exposure to variability in expected future
cash flows (such variability to be referred to hereafter as Cash Flow
Variability) related to fixed-price sales contracts.
2.
We will purchase
futures contracts in quantities reasonably expected to hedge effectively our
exposure to Cash Flow Variability related to each fixed-price sales contract
that we enter into after the date of the policy.
3.
We may offer a
fixed-price sales contract to a customer only if the following three conditions
are met:
a.
We purchase futures
contracts in quantities reasonably expected to hedge effectively our exposure
to Cash Flow Variability related to the fixed-price sales contract;
b.
We reasonably expect
we will have funds sufficient: (i) to make the initial margin deposit(s)
related to the intended futures contracts; and (ii) to cover estimated
margin calls related to these futures contracts; and
c.
For any contract
covering 2.5 million or more gasoline gallon equivalents of CNG or LNG per
year (or any contract that, combined with previous contracts that year, would
cause the total gasoline gallon equivalents contracted for to exceed
7.5 million gasoline gallon equivalents that year), we consult with the
derivative committee regarding the proposed transaction, and the derivative
committee approves both the offer of the fixed-price sales contract(s) and the
purchase of the associated futures contracts.
4.
When we enter into a
fixed-price sales contract according to paragraph 3 above, we will
purchase sufficient futures contracts to hedge our estimated exposure to the
basis differential between: (a) the price of natural gas at the NYMEX Henry Hub
delivery point, and (b) the price of natural gas at the customers delivery
point.
5.
If, during the
duration of a fixed-price sales contract (including, without limitation, a
contract signed before the adoption of this policy, a contract entered into
after the adoption of this policy where futures contracts were not originally
purchased to hedge the contract, and a contract that subsequently experiences a
significant increase in volume that was not originally contemplated when the
original futures contracts were purchased to hedge the contract), we do not
have associated futures contracts in place that are sufficient to hedge
effectively our estimated exposure to Cash Flow Variability related to that
fixed-price sales contract, we may purchase futures contracts in quantities
reasonably expected to hedge effectively our exposure to Cash Flow Variability
related to that fixed-price sales contract, but only if the following two
conditions are met:
a.
We reasonably expect
we will have funds sufficient: (i) to make the initial margin deposit(s)
related to the intended futures contracts; and (ii) to cover estimated
margin calls related to these futures contracts; and
b.
For any fixed-price
sales contract covering 1.5 million or more gasoline gallon equivalents
per year (or any such contract that, combined with previous such contracts that
year, would cause the total gasoline equivalents contracted for to exceed
5 million gasoline gallon equivalents that year), we consult with the
derivative committee regarding the proposed transaction, and it approves the
purchase of the futures contracts.
6.
When we purchase
futures contracts in accordance with paragraph 5 above, we may purchase
additional futures contracts to hedge our estimated exposure to the basis
differential between: (a) the price of natural gas at the NYMEX Henry Hub
delivery point, and (b) the price of natural gas at the customers delivery
point.
15
7.
We
will not sell or otherwise dispose of a futures contract during the duration of
the associated fixed-price sales contract.
8.
We
will attempt to qualify all futures contracts for hedge accounting as cash flow
hedges under SFAS 133.
Due to
the restrictions of our revised hedging policy, as well as the rising cost of
futures contracts resulting from the loss of Mr. Pickens guarantee to
Sempra, we expect to offer significantly fewer fixed-price sales contracts to
our customers. If we do offer a fixed-price sales contract, we anticipate
including a price component that would cover our increased costs as well as a
return on our estimated cash requirements over the duration of the underlying
futures contract. The amount of this price component will vary based on the
anticipated volume to be covered under the fixed-price sales contract.
Critical
Accounting Policies
Our
discussion and analysis of our financial condition and results of operations is
based upon our financial statements, which have been prepared in accordance
with U.S. generally accepted accounting principles. The preparation of
financial statements requires management to make estimates and judgments that
affect the reported amounts of assets and liabilities, revenue and expenses,
and disclosures of contingent assets and liabilities as of the date of the
financial statements. On a periodic basis, we evaluate our estimates, including
those related to revenue recognition, accounts receivable reserves, notes
receivable reserves, inventory reserves, asset retirement obligations,
derivative values, income taxes, and the market value of equity instruments
granted as stock-based compensation, among others. We use historical
experience, market quotes, and other assumptions as the basis for making estimates.
Actual results could differ from those estimates under different assumptions or
conditions. We believe the following critical accounting policies affect our
more significant judgments and estimates used in the preparation of our
financial statements.
Revenue Recognition
We
recognize revenue on our gas sales and for our O&M services in accordance
with SEC Staff Accounting Bulletin No. 104,
Revenue Recognition
, which requires that four basic criteria
must be met before revenue can be recognized: (1) persuasive evidence of
an arrangement exists; (2) delivery has occurred and title and the risks
and rewards of ownership have been transferred to the customer or services have
been rendered; (3) the price is fixed or determinable; and (4) collectability
is reasonably assured. Applying these factors, we typically recognize revenue
from the sale of natural gas at the time fuel is dispensed or, in the case of
LNG sales agreements, delivered to the customers storage facility. We
recognize revenue from operation and maintenance agreements as we provide the
O&M services.
In
certain transactions with our customers, we agree to provide multiple products
or services, including construction of and either leasing or sale of a station,
providing operations and maintenance to the station, and sale of fuel to the
customer. We evaluate the separability of revenues for deliverables based on
the guidance set forth in EITF No. 00-21, which provides a framework for
establishing whether or not a particular arrangement with a customer has one or
more deliverables. To the extent we have adequate objective evidence of the
values of separate deliverable items under a contract, we allocate the revenue
from the contract on a relative fair value basis at the inception of the
arrangement. If the arrangement contains a lease, we use the existing evidence
of fair value to separate the lease from the other deliverables.
We
account for our leasing activities in accordance with SFAS No. 13,
Accounting for Leases
. Our existing
station leases are sales-type leases, giving rise to profit at the delivery of
the leased station. Unearned revenue is amortized into income over the life of
the lease using the effective interest method. For those arrangements, we
recognize gas sales and operations and maintenance service revenues as earned
from the customer on a volume-delivered basis.
We
recognize revenue on fueling station construction projects where we sell the
station to the customer using the completed contract method in AICPA Statement
of Position 81-1,
Accounting for
Performance of Construction Type and Certain Production Type Contracts
.
Derivative Activities
We
account for our derivative instruments, specifically our futures contracts, in
accordance with SFAS No. 133,
Accounting
for Derivative Instruments and Hedging Activities
, as amended (SFAS
133). SFAS 133 requires the recognition of all derivatives as either assets or
liabilities in the consolidated balance sheet and the measurement of those
instruments at fair value. Our derivatives did not qualify for hedge accounting
under SFAS 133 for the years ended December 31, 2004, 2005 and 2006. As
such, changes in the fair value of the derivatives for the years ended
December 31, 2004, 2005 and 2006, were recorded directly to our
consolidated statements of operations. We determine the fair value of our
derivatives at the end of each reporting period based on quoted market prices
from the NYMEX. We did not have any derivative instruments during the
first nine months of 2007.
16
We
record gains or losses realized on our derivative instruments during the period
in the line item derivative (gains) losses in our consolidated statements of
operations. We also mark-to-market our open positions at the end of each
reporting period with the resulting gain or loss recorded to derivative (gains)
losses in our consolidated statements of operations.
Fixed Price and Price Cap
Sales Contracts
Our
contracts to sell CNG and LNG at a fixed price or a variable price subject to a
cap are, for accounting purposes, firm commitments, and U.S. generally accepted
accounting principles do not require or allow us to record a loss until the
delivery of the gas and corresponding sale of the product occurs. When we enter
into these fixed price or price cap contracts with our customers, the price is
set based on the prevailing index price of natural gas at that time. However,
the index price of natural gas constantly changes, and a difference between the
fixed price of the natural gas included in the customers contract price and
the corresponding index price of gas typically develops after we enter into the
sales contract. We have entered into several contracts to sell LNG or CNG to
customers at a fixed price or an index-based price that is subject to a fixed
price cap. We have also generally entered into natural gas futures contracts to
offset economically the adverse impact of rising natural gas prices. We have
also periodically sold the underlying futures contracts related to our fixed
price and price cap contracts. At September 30, 2007, we did not own any
futures contracts related to our fixed price and price cap contracts. Since
entering into the fixed price and price cap sales contracts, the price of
natural gas has generally increased.
From
an accounting perspective, during periods of rising natural gas prices, our
futures contracts have generally been marked-to-market through the recognition
of a derivative asset and a corresponding derivative gain in our statements of
operations. However, because our contracts to sell LNG or CNG to our customers
at fixed prices or an index-based price that is subject to a fixed price cap
are not derivatives for purposes of U.S. generally accepted accounting
principles, a liability or a corresponding loss has not been recognized in our
statements of operations during this historical period of rising natural gas
prices for the future commitments under these contracts. As a result, our
statements of operations do not reflect our firm commitments to deliver LNG or
CNG at prices that are below, and in some cases, substantially below, the
prevailing market price of natural gas (and therefore LNG or CNG).
The
following table summarizes important information regarding our fixed price and
price cap supply contracts under which we are required to sell fuel to our
customers as of September 30, 2007:
|
|
Estimated
volumes (a)
|
|
Average
price (b)
|
|
Contracts
duration
|
|
CNG fixed price contracts
|
|
1,490,621
|
|
$
|
1.13
|
|
through
12/13
|
|
LNG fixed price contracts
|
|
17,210,187
|
|
$
|
0.38
|
|
through 7/09
|
|
CNG price cap contracts
|
|
5,027,520
|
|
$
|
0.86
|
|
through
12/09
|
|
LNG price cap contracts
|
|
9,663,782
|
|
$
|
0.56
|
|
through
12/08
|
|
(a)
Estimated
volumes are in gasoline gallon equivalents for CNG contracts and are in LNG
gallons for LNG contracts and represent the volumes we anticipate delivering
over to remaining duration of the contracts.
(b)
Average
prices are in gasoline gallon equivalents for CNG contracts and are in
LNG gallons for LNG contracts. The average prices represent the natural
gas commodity component embedded in the customers contract.
The
price of natural gas has generally increased since we entered into these
contracts and fixed or capped the price of CNG or LNG that we sell to the
customers. If these contracts had a notional amount as defined under GAAP, then
the contracts would be considered derivatives and we would record a loss based
on estimated future volumes and the estimated excess of current market prices
for natural gas above the cost of the natural gas commodity component of our
customers fixed price or price cap. However, because the contracts have no
minimum purchase requirements, they are not considered derivatives and any
estimated future losses under these contracts cannot be accrued in our
financial statements under GAAP and we recognize the actual results of
performing under the contract as the fuel is delivered. If we applied a
derivative valuation methodology to these contracts using estimated volumes
along with other assumptions, including forward pricing curves and discount
rates, we estimate our pre-tax net income would have been lower (higher) by the
following ranges for the periods indicated:
December 31, 2004
|
|
$
|
3,646,338
|
|
to
|
|
$
|
4,456,636
|
|
December 31, 2005
|
|
$
|
15,148,070
|
|
to
|
|
$
|
18,514,308
|
|
December 31, 2006
|
|
$
|
(14,267,259
|
)
|
to
|
|
$
|
(17,437,761
|
)
|
Nine months ended September 30, 2007
|
|
$
|
2,348,440
|
|
to
|
|
$
|
2,870,316
|
|
17
At
September 30, 2007, based on natural gas futures prices as of that date, we
estimate we will incur between $5.0 million and $6.2 million to cover the
increased price of natural gas above the inherent price of natural gas embedded
in our 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, 2007, and these estimates may change based on future natural gas
prices and may be significantly higher or lower.
Our
volumes under these contracts, in gasoline gallon equivalents, expire as
follows:
October 1, 2007 through December 31, 2007
|
|
5,490,150
|
|
2008
|
|
15,250,419
|
|
2009
|
|
2,486,896
|
|
2010
|
|
230,000
|
|
2011
|
|
230,000
|
|
2012
|
|
230,000
|
|
2013
|
|
230,000
|
|
These
amounts are based on estimates involving a high degree of judgment and actual
results may vary materially from these estimates. These amounts have not been
recorded in our statements of operations as they are non-GAAP.
Income Taxes
We
compute income taxes under the asset and liability method. This method requires
the recognition of deferred tax assets and liabilities for temporary
differences between the financial reporting basis and the tax basis of our
assets and liabilities. The impact on deferred taxes of changes in tax rates
and laws, if any, are applied to the years during which temporary differences
are expected to be settled and are reflected in the consolidated financial
statements in the period of enactment. We record a valuation allowance against
any deferred tax assets when management determines it is more likely than not
that the assets will not be realized. When evaluating the need for a valuation
analysis, we use estimates involving a high degree of judgment including
projected future income and the amounts and estimated timing of the reversal of
any deferred tax liabilities.
Our income tax benefit was $9.0 million in
the quarter ended September 30, 2006, which includes an increase in the valuation
allowance of $17.6 million. In the Managements Discussion and Analysis of
Financial Condition Results of Operations Quarterly Results of Operations section
previously filed in our initial public offering prospectus filed with the SEC
on May 25, 2007, this increase in the valuation allowance was reflected in the
quarter ended December 31, 2006.
Stock-Based Compensation
Effective
January 1, 2006, we account for stock options granted using Statement of
Financial Accounting Standards
No. 123(R),
Share-Based Payment
,
(SFAS 123(R))which has replaced SFAS 123 and APB 25. Under SFAS 123(R), companies
are no longer able to account for share-based compensation transactions using
the intrinsic method in accordance with APB 25, but are required to account for
such transactions using a fair-value method and recognize the expense in the
statements of operations. We adopted the provisions of SFAS 123(R) using
the prospective transition method. Under the prospective transition method,
only new awards, or awards that have been modified, repurchased or cancelled
after January 1, 2006 are accounted for using the fair value method.
We
accounted for awards outstanding as of December 31, 2005 using the
accounting principles under SFAS 123. Under SFAS 123, for options granted
before January 1, 2006, the fair value of employee stock options was
estimated using the Black-Scholes option pricing model, which requires the use
of managements judgment in estimating the inputs used to determine fair value.
We elected, under the provisions of SFAS 123, to account for employee
stock-based compensation under APB 25 during the years ended December 31,
2004 and 2005. In the statements of operations, we recorded no compensation
expense in 2004 and 2005 because the fair value of our common stock was equal
to the exercise price on the date of grant of the options. Therefore, there was
no intrinsic value to recognize in the statements of operations. However, the
footnotes to our consolidated financial statements set forth in our prospectus
dated May 25, 2007 (and filed with the SEC on May 25, 2007) disclose
the impact on net income in 2004 and 2005 of using the grant date fair value
using the Black-Scholes option pricing model.
As of
December 31, 2005, there were no unvested stock options. Therefore, the
impact of SFAS 123(R) has been reflected in the condensed consolidated statements
of operations for share-based awards granted in 2006 and 2007.
18
Impairment of Goodwill
and Long-lived Assets
We
assess our goodwill for impairment at least annually (or more frequently if
there is an indicator of impairment) based on Statement of Financial Accounting
Standards No. 142 (SFAS 142),
Goodwill
and Other Intangible Assets.
An initial assessment of impairment is
made by comparing the fair value of the operations with goodwill, as determined
in accordance with SFAS 142, to the book value. If the fair value is less than
the book value, an impairment is indicated and we must perform a second test to
measure the amount of the impairment. In the second test, we calculate the
implied fair value of the goodwill by deducting the fair value of all tangible
and intangible net assets of the operations with goodwill from the fair value
determined in step one of the assessment. If the carrying value of the goodwill
exceeds this calculated implied fair value of the goodwill, we will record an
impairment charge. We performed our annual tests of goodwill as of
December 31, 2004, 2005 and 2006, and there was no impairment indicated.
There was no indication of impairment from January 1, 2007 through September
30, 2007.
Recently Issued
Accounting Pronouncements
In
June 2006, the FASB issued FASB Interpretation No. 48,
Accounting for Uncertainty in Income Taxes
(FIN 48), which prescribes a recognition threshold and measurement
attribute for the financial statement recognition and measurement of a tax
position taken or expected to be taken in a tax return. The interpretation also
provides guidance on derecognition, classification, interest and penalties,
accounting in interim periods, disclosure, and transition. FIN 48 is
effective for fiscal years beginning after December 15, 2006. The adoption of
FIN 48 did not have a material impact on our financial statements.
In
June 2006, the FASB ratified its consensus on EITF Issue No. 06-3,
How Taxes Collected from Customers and Remitted to
Governmental Authorities Should Be Presented in the Income Statement
(EITF 06-3). The scope of EITF 06-3 includes any tax assessed by a governmental
authority that is imposed concurrent with or subsequent to a revenue-producing
transaction between a seller and a customer and excludes taxes that are
assessed on gross receipts or that are an inventoriable cost. For taxes within
the scope of this issue that are significant in amount, the consensus requires
the following disclosures: (i) the accounting policy elected for these
taxes and (ii) the amount of the taxes reflected gross in the income
statement on an interim and annual basis for all periods presented. The
consensus is effective for interim and annual periods beginning after December 15,
2006. We have historically presented sales taxes and excise taxes on sales to
our customers on a net basis in our financial statements both prior to and
subsequent to the adoption of EITF 06-3.
In
September 2006, the FASB issued Statement of Financial Accounting Standards
No. 157,
Fair Value Measurements
(SFAS 157), which defines fair value, establishes a framework for
measuring fair value in generally accepted accounting principles and expands
disclosures about fair value measurements. SFAS 157 is effective for
fiscal years beginning after November 15, 2007 and all interim periods
within those fiscal years. Earlier application is permitted provided that the
reporting entity has not yet issued interim or annual financial statements for
that fiscal year. We are currently evaluating the impact, if any, that
SFAS 157 may have on our financial statements.
In
February 2007, the FASB issued Statement of Financial Accounting Standard No.
159,
The
Fair Value Option for
Financial Assets and Financial Liabilities
(SFAS 159). SFAS 159
permits entities to choose to measure certain financial instruments and other
eligible items at fair value when the items are not otherwise currently
required to be measured at fair value. Under SFAS 159, the decision to measure
items at fair value is made at specified election dates on an irrevocable
instrument-by-instrument basis. Entities electing the fair value option would
be required to recognize changes in fair value in earnings and to expense
upfront costs and fees associated with the item for which the fair value option
is elected. Entities electing the fair value option are required to
distinguish, on the face of the statement of financial position, the fair value
of assets and liabilities for which the fair value option has been elected and
similar assets and liabilities measured using another measurement attribute. If
elected, SFAS 159 will be effective as of the beginning of the first fiscal
year that begins after November 15, 2007, with earlier adoption permitted if all
of the requirements of SFAS 157 are adopted. We are currently evaluating the
impact, if any, that SFAS 159 may have on our financial statements.
19
Results
of Operations
The following is a more detailed discussion of our
financial condition and results of operations for the periods presented:
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
|
|
2006
|
|
2007
|
|
2006
|
|
2007
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
100.0
|
%
|
100.0
|
%
|
100.0
|
%
|
100.0
|
%
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
Cost of sales
|
|
82.0
|
%
|
69.3
|
%
|
84.8
|
%
|
72.8
|
%
|
Derivative losses
|
|
292.2
|
%
|
0.0
|
%
|
100.7
|
%
|
0.0
|
%
|
Selling, general and administrative
|
|
25.2
|
%
|
32.6
|
%
|
22.9
|
%
|
29.8
|
%
|
Depreciation and amortization
|
|
7.3
|
%
|
6.2
|
%
|
6.5
|
%
|
5.8
|
%
|
Total operating expenses
|
|
406.6
|
%
|
108.1
|
%
|
214.9
|
%
|
108.4
|
%
|
Operating loss
|
|
(306.6
|
)%
|
(8.2
|
)%
|
(115.0
|
)%
|
(8.4
|
)%
|
|
|
|
|
|
|
|
|
|
|
Interest income, net
|
|
(1.8
|
)%
|
(4.8
|
)%
|
(1.3
|
)%
|
(2.6
|
)%
|
Other expense, net
|
|
0.2
|
%
|
0.2
|
%
|
0.0
|
%
|
0.3
|
%
|
Loss before income taxes
|
|
(305.0
|
)%
|
(3.5
|
)%
|
(113.7
|
)%
|
(6.1
|
)%
|
Income tax expense (benefit)
|
|
(40.6
|
)%
|
1.8
|
%
|
(16.6
|
)%
|
0.7
|
%
|
Net loss
|
|
(264.4
|
)%
|
(5.3
|
)%
|
(97.1
|
)%
|
(6.8
|
)%
|
Three
Months Ended September 30, 2007 Compared to Three Months Ended September 30,
2006
Revenue.
Revenue
increased by $7.0 million to $29.2 million in the three months ended
September 30, 2007, from $22.2 million in the three months ended September
30, 2006. This increase was primarily the result of an increase in the number
of CNG and LNG gallons delivered from 18.2 million gasoline gallon equivalents
in the third quarter of 2006 to 20.0 million gasoline gallon equivalents in the
third quarter of 2007. One of our new transit customers (Long Island Bus, NY)
and additional buses at one of our current customers (Foothill Transit,
California) together accounted for 1.7 million gasoline gallon equivalents
of the increase. The remaining increase in gasoline gallon equivalents
delivered was due to the addition of other smaller new customers and growth
from our existing customers. Revenue also increased between periods as we
recorded $4.5 million of revenue related to fuel tax credits in the third
quarter of 2007, which were not included in the prior period as the credits first
became available in October 2006.
Cost of sales.
Cost
of sales increased by $2.1 million to $20.3 million in the three
months ended September 30, 2007, from $18.2 million in the three months ended
September 30, 2006. This increase was primarily the result of an increase in
costs related to delivering more CNG and LNG between periods.
Derivative losses.
We
incurred derivative losses of $65.0 million in the three months ended September
30, 2006, related to mark-to-market losses recorded on certain futures
contracts related to future periods. We incurred no derivative gains or losses
during the three months ended September 20, 2007 because we did not own any
derivative instruments during this period.
Selling, general and administrative.
Selling,
general and administrative expenses increased by $3.9 million to
$9.5 million in the three months ended September 30, 2007, from
$5.6 million in the three months ended September 30, 2006. A significant
portion of this increase related to $1.6 million of stock option expense
recorded in the third quarter of 2007 associated with stock options we granted
to our employees and directors in May 2007 and in September 2007. In addition,
salaries and benefits increased between periods by $0.7 million, primarily
related to increased salaries and compensation due to our executive officers
and the hiring of additional employees. Our professional service fees increased
$0.6 million between periods primarily for legal, audit and consulting services
related to our status as a public company. Our bad debt expense increased $0.2
million between periods as we provided a reserve against loans made to a
vehicle manufacturer during the three months ended September 30, 2007. Our
business insurance costs also increased $0.2 million between periods primarily
due to an increase in premiums related to our directors and officers
insurance between periods.
Depreciation and amortization.
Depreciation
and amortization increased by $0.2 million to $1.8 million in the
three months ended September 30, 2007, from $1.6 million in the three
months ended September 30, 2006. This increase was primarily the result of
additional depreciation expense in the three months ended September 30, 2007
related to increased property and equipment balances between periods, primarily
related to our expanded station network and fleet of LNG tanker trailers.
20
Interest income, net.
Interest
income, net, increased by $1.0 million from $0.4 million in the three
months ended September 30, 2006, to $1.4 million for the three months ended
September 30, 2007. This increase was primarily the result of an increase in
interest income in the three months ended September 30, 2007 due to higher
average cash balances on hand in the third quarter of 2007 associated with the
proceeds received from our initial public offering in May 2007.
Other expense, net.
There
was no significant change in other expense, net, between the three months ended
September 30, 2006 and the three months ended September 30, 2007.
Nine
Months Ended September 30, 2007 Compared to Nine Months Ended September 30,
2006
Revenue.
Revenue
increased by $23.2 million to $88.0 million in the nine months ended September
30, 2007, from $64.8 million in the nine months ended September 30, 2006. This
increase was primarily the result of an increase in the CNG and LNG delivered
between periods from 50.7 million gasoline gallon equivalents in the first nine
months of 2006 to 57.1 million gasoline gallon equivalents in the first nine
months of 2007. One of our new transit customers (Long Island Bus, NY) and one
of our new airport customers (Los Angeles International Airport shuttle busses)
together accounted for 4.1 million gasoline gallon equivalents of the
increase. The remaining increase in gasoline gallon equivalents delivered was
due to the addition of other smaller new customers and growth from our existing
customers. Revenue also increased in the first nine months of 2007 as we
recorded $12.8 million of revenue related to fuel tax credits during the
period, which were not included in the prior period as the credits first became
available in October 2006. We also experienced an increase between periods
of $3.1 million in station construction revenue. Offsetting these
increases was a decrease in our average price per gallon between periods. Our average
price per gallon, excluding tax credits, was $1.25 in the first nine months of
2007, which represents a $.02 per gallon decrease from the first nine months of
2006.
Cost of sales.
Cost
of sales increased by $9.2 million to $64.1 million in the nine months
ended September 30, 2007, from $54.9 million in the nine months ended
September 30, 2006. This increase was primarily the result of an increase in
costs related to delivering more CNG and LNG between periods. Also contributing
to the increase in cost of sales between periods is a $2.8 million increase in
costs related to construction activities during the nine month period ended
September 30, 2007. In addition, our cost of sales increased between periods as
our average cost per gallon rose to $1.12 in the first nine months of 2007,
which represents a $.04 per gallon increase over the first nine months of 2006.
Derivative losses.
We
incurred derivative losses of $65.3 million in the nine months ended September
30, 2006, primarily related to mark-to-market losses recorded on certain
futures contracts related to future periods. We incurred no derivative gains or
losses during the nine months ended September 30, 2007 because we did not own any
derivative instruments during this period.
Selling, general and administrative.
Selling,
general and administrative expenses increased by $11.4 million to
$26.3 million in the nine months ended September 30, 2007, from
$14.9 million in the nine months ended September 30, 2006. The increase
was primarily related to recording $5.4 million of stock option expense in the
second and third quarters of 2007 associated with the stock options we granted
to our employees and directors in May 2007 and in September 2007. There was an
increase of $2.1 million in salaries and benefits between periods primarily
related to the increased compensation due to our executive officers and the
hiring of additional employees. Our employee headcount increased from 96 at
September 30, 2006 to 118 at September 30, 2007. In addition, our rent expense
increased $0.2 million between periods as we acquired additional office space
between periods and our travel and entertainment expenses increased $0.4
million between periods, primarily related to increased travel related to our
sales team. Our marketing expenses increased $0.9 million between periods,
primarily due to certain advertising we conducted related to our refuse market
segment and in the Ports of Los Angeles and Long Beach. Our bad debt expense
increased $1.0 million between periods as we provided a reserve against
loans made to a vehicle manufacturer and two of our vehicle financing customers
during the nine months ended September 30, 2007. Our professional service fees
increased $0.9 million between periods primarily for legal, audit and
consulting services related to our status as a public company. Our business
insurance costs also increased $0.3 million between periods, primarily due to
premium increases in our directors and officers insurance between periods,
and our credit card fees increased $0.2 million between periods as more of our
retail customers are using credit cards to purchase their fuel.
Depreciation and amortization.
Depreciation
and amortization increased by $0.9 million to $5.1 million in the nine
months ended September 30, 2007, from $4.2 million in the nine months ended
September 30, 2006. This increase was primarily related to the result of
additional depreciation expense in the nine months ended September 30, 2007
related to increased property and equipment balances between periods, primarily
related to our expanded station network and fleet of LNG tanker trailers.
21
Interest income, net.
Interest
income, net, increased by $1.5 million from $0.8 million in the nine
months ended September 30, 2006, to $2.3 million for the nine months ended
September 30, 2007. This increase was primarily the result of a decrease in
interest expense in the nine months ended September 30, 2007 due to the
conversion of $4 million of convertible notes in April 2006, which
eliminated the interest expense on these notes. In addition, interest income
for the nine months ended September 30, 2007 increased in comparison to the
nine months ended September 30, 2006 due to higher average cash balances on
hand in the first nine months of 2007 associated with the proceeds received
from our initial public offering in May 2007.
Other expense, net.
Other
expense, net, increased by $0.2 million to $0.2 million of expense in the nine
months ended September 30, 2007. The increase was primarily related to costs
related to station closures recorded in the second and third quarters of 2007.
Seasonality
and Inflation
To some extent, we experience seasonality in our
results of operations. Natural gas vehicle fuel consumed by some of our
customers tends to be higher in summer months when buses and other fleet
vehicles use more fuel to power their air conditioning systems. Natural gas
commodity prices tend to be higher in the fall and winter months due to
increased overall demand for natural gas for heating during these periods.
Since our inception, inflation has not significantly
affected our operating results. However, costs for construction, taxes,
repairs, maintenance and insurance are all subject to inflationary pressures
and could affect our ability to maintain our stations adequately, build new
stations, build new LNG plants and expand our existing facilities.
Liquidity
and Capital Resources
Historically, our principal sources of liquidity have
consisted of cash provided by operations and financing activities, cash and
cash equivalents, the issuance of common stock, sometimes in association with
the exercise of certain warrants that were callable at our option, and in 2006
a revolving line of credit with Boone Pickens, our majority stockholder. In May
2007, we completed our initial public offering of 10,000,000 shares of common
stock at a public offering price of $12.00 per share. Net cash proceeds from
the initial public offering were approximately $108.5 million, after deducting
underwriting discounts, commissions and offering expenses. In addition to
funding operations, our principal uses of cash have been, and are expected to
be, the construction of new fueling stations, the construction of a new LNG
liquefaction plant in California, the purchase of new LNG tanker trailers, the
financing of natural gas vehicles for our customers, and general corporate
purposes, including making deposits to support our derivative activities,
geographic expansion (domestically and internationally), expanding our sales
and marketing activities, and for working capital for our expansion. We
financed our operations in the first nine months of 2007 primarily through cash
provided by operations and financing activities. At September 30, 2007, we had
total cash and cash equivalents of $74.8 million compared to $0.9 million
at December 31, 2006.
Cash provided by operating activities was $8.6 million
for the nine months ended September 30, 2007, compared to cash used in
operating activities of $37.2 million for the nine months ended September 30,
2006. The change in operating cash flow was primarily related to the change in
our margin deposits between periods. In the first nine months of 2006, we made
net margin deposits on futures contracts of $30.9 million, and in the first
nine months of 2007, we received a refund of $22.9 million of margin deposits. The
$22.9 million of margin deposits received in 2007 is recorded in other
receivables as these deposits were transferred to other receivables in the
fourth quarter of 2006 in connection with a transaction we completed with Boone
Pickens in December 2006. For more information, see Risk Management Activities
August 2006 Purchase of Futures Contracts and December 2006 Assumption by
Boone Pickens above. Offsetting this increase are (i) increases in our fuel
tax credit receivable between periods, the majority of which we receive on an
annual basis after we file our income tax return, and (ii) an increase between
periods in the deposits we made on the production of certain LNG trucks we
anticipate will be operated in the Ports of Los Angeles and Long Beach. We also
experienced an increase in cash provided by operating activities between
periods due to a reduction in our income taxes paid between periods of $6.3
million.
Cash used in investing activities was $45.1 million
for the nine months ended September 30, 2007, compared to $11.3 million for the
nine months ended September 30, 2006. The $33.8 million increase between
periods was primarily due to increased purchases of property and equipment and
increased construction in progress activity in the first nine months of 2007,
including approximately $17 million that we spent on developing our LNG
liquefaction plant in California. We also purchased $14.8 million of short-term
investments in the third quarter of 2007 with excess cash balances.
22
Cash provided by financing activities for the nine
months ended September 30, 2007 was $110.3 million, compared to cash provided
by financing activities of $21.2 million for the nine months ended September
30, 2006. The $89.1 million increase between periods is primarily attributable
to the net proceeds of $110.2 million we received from our initial public
offering in May 2007, as compared to the proceeds of $22.0 million we received
from the issuance of common stock during the nine months ended September 30,
2006.
Our financial position and liquidity are, and will be,
influenced by a variety of factors, including our ability to generate cash
flows from operations, deposits and margin calls on our futures positions, the
level of any outstanding indebtedness and the interest we are obligated to pay
on this indebtedness, and our capital expenditure requirements, which consist
primarily of station construction, LNG plant construction, and the purchase of
LNG tanker trailers and equipment.
We intend to fund our principal liquidity requirements
through cash and cash equivalents, cash provided by operations and, if
necessary, through debt or equity financings. We believe our sources of
liquidity will be sufficient to meet the cash requirements of our operations
for at least the next twelve months.
Capital
Expenditures
We expect to make capital expenditures, net of grant
proceeds, of approximately $19.3 million in 2007 to construct new natural gas
fueling stations, purchase LNG tanker trailers, and for general corporate
purposes. Additionally, we have budgeted approximately $65 million over
the course of 2007 and 2008 to construct an LNG liquefaction plant in
California which we are in the initial stages of building and anticipate will
be operational in the summer of 2008. We also anticipate using $15 to
$20 million from the proceeds of our initial public offering to finance
the purchase of natural gas vehicles by our customers.
Contractual
Obligations
The following represents the scheduled maturities of
our contractual obligations as of September 30, 2007:
|
|
Payments Due by Period
|
|
Contractual Obligations:
|
|
Total
|
|
Remainder of
2007
|
|
2008 and
2009
|
|
2010 and
2011
|
|
2012 and
beyond
|
|
Capital lease obligations(a)
|
|
$
|
239,813
|
|
$
|
14,916
|
|
$
|
133,691
|
|
$
|
91,206
|
|
$
|
0
|
|
Operating lease commitments(b)
|
|
4,951,437
|
|
325,842
|
|
2,361,130
|
|
1,349,217
|
|
915,248
|
|
Take-or-pay LNG purchase contracts(c)
|
|
1,955,625
|
|
651,875
|
|
1,303,750
|
|
0
|
|
0
|
|
Construction contracts(d)
|
|
2,488,667
|
|
1,461,167
|
|
1,027,500
|
|
0
|
|
0
|
|
Other long-term contract liabilities(e)
|
|
16,776,106
|
|
12,721,757
|
|
4,054,349
|
|
0
|
|
0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
26,411,648
|
|
$
|
15,175,557
|
|
$
|
8,880,420
|
|
$
|
1,440,423
|
|
$
|
915,248
|
|
(a)
Consists
of obligations under a lease of capital equipment used to finance such
equipment. Amounts do not include interest as it is immaterial.
(b)
Consists
of various space and ground leases for our offices and fueling stations as well
as leases for equipment.
(c)
The
amounts in the table represent our estimates for our fixed LNG purchase
commitments under two take or pay contracts. In October 2007, we entered into
a 10-year take-or-pay commitment for 45,000 LNG gallons per day from an LNG
plant to be constructed in Arizona, which commitment is not reflected in the
table.
(d)
Consists
of our obligations to fund various fueling station construction projects, net
of amounts funded through September 30, 2007, and excluding contractual
commitments related to station sales contracts.
(e)
Consists
of our obligations to fund certain vehicles under binding purchase agreements
and our commitments under binding purchase agreements we have entered into to
acquire certain equipment and services related to the construction of our LNG
plant in California.
23
Off-Balance
Sheet Arrangements
At September 30, 2007, we had the following
off-balance sheet arrangements:
outstanding
standby letters of credit totaling $16,000,
outstanding
surety bonds for construction contracts and general corporate purposes totaling
$5.5 million,
two take or
pay contracts for the purchase of LNG,
operating
leases where we are the lessee,
capital
leases where we are the lessor and owner of the equipment, and
firm
commitments to sell CNG and LNG at fixed prices or index-plus prices subject to
a price cap.
We provide standby letters of credit primarily to
support facility leases and surety bonds primarily for construction contracts
in the ordinary course of business, as a form of guarantee. No liability has
been recorded in connection with standby letters of credit or surety bonds as
we do not believe, based on historical experience and information currently
available, that it is probable that any amounts will be required to be paid
under these arrangements.
We have entered into contracts with two vendors to
purchase LNG that require us to purchase minimum volumes from the vendors. Both
of the contracts expire in June 2008. The minimum commitments under these two
contracts are included in the table set forth under Take-or-pay LNG purchase
contracts above.
We have entered into operating lease arrangements for
certain equipment and for our office and field operating locations in the
ordinary course of business. The terms of our leases expire at various dates
through 2016. Additionally, in November 2006, we entered into a ground
lease for 36 acres in California on which we are in the initial stages of
building an LNG liquefaction plant. We have budgeted approximately
$65 million over the course of 2007 and 2008 to construct this plant. The
lease is for an initial term of 30 years, beginning on the date that the
plant commences operations, and requires annual base rent payments of $230,000
per year, plus $130,000 per year for each 30,000,000 gallons of production
capacity, subject to future adjustment based on consumer price index changes.
We must also pay a royalty to the landlord for each gallon of LNG produced at
the facility, as well as for certain other services that the landlord will
provide. Our obligations under the lease are contingent on us obtaining the
necessary permits and approvals required in the lease related to the
construction and operation of the LNG liquefaction plant, which are in process.
As the payments are contingent obligations, they are not included in Operating
lease commitments in the Contractual Obligations table set forth above.
We are also the lessor in various leases with our
customers, whereby our customers lease from us certain stations and equipment
that we own. The leases generally qualify as sales-type leases for accounting
purposes, which result in our customers, the lessees, reflecting the property
and equipment on their balance sheets.
Item
3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Risk
We are subject to market
risk with respect to our sales of natural gas, which has historically been
subject to volatile market conditions. Our exposure to market risk is
heightened when we have a fixed price or price cap sales contract with a
customer that is not covered by a futures contract, or when we are otherwise
unable to pass through natural gas price increases to customers. Natural gas
prices and availability are affected by many factors, including weather
conditions, overall economic conditions and foreign and domestic governmental
regulation and relations.
Natural gas costs represented 63% of our cost of sales
for 2006 and 59% of our cost of sales for the nine months ended September 30,
2007. Prices for natural gas over the seven-year and nine-month period from
December 31, 1999 through September 30, 2007, based on the NYMEX daily
futures data, has ranged from a low of $1.65 per Mcf to a high of $19.38 per
Mcf. At September 30, 2007, the NYMEX index price of natural gas was $5.23
per Mcf.
To reduce price risk caused by market fluctuations in
natural gas, we may enter into exchange traded natural gas futures contracts.
These arrangements also expose us to the risk of financial loss in situations
where the other party to the contract defaults on its contract or there is a
change in the expected differential between the underlying price in the
contract and the actual price of natural gas we pay at the delivery point.
24
We account for these futures contracts in accordance
with SFAS No. 133,
Accounting for Derivative Instruments and Hedging
Activities
. Under this standard, the accounting for changes
in the fair value of a derivative depends upon whether it has been designated
in a hedging relationship and, further, on the type of hedging relationship. To
qualify for designation in a hedging relationship, specific criteria must be
met and appropriate documentation maintained. Our futures contracts did not
qualify for hedge accounting under SFAS 133 for the years ended December 31,
2004, 2005 and 2006, and changes in the fair value of the derivatives were
recorded directly to our consolidated statements of operations at the end of
each reporting period. We did not own any derivative instruments during the
first nine months of 2007.
The fair value of the futures contracts we use is
based on quoted prices in active exchange traded or over the counter markets.
The fair value of these futures contracts is continually subject to change due
to changing market conditions. The net effect of the realized and unrealized
gains and losses related to these derivative instruments for the year ended
December 31, 2006 was a $79.0 million decrease to pre-tax income. We
did not have any futures contracts outstanding during the three or nine months
ended September 30, 2007. In an effort to mitigate the volatility in our
earnings related to futures activities, in February 2007, our board of
directors adopted a revised natural gas hedging policy which restricts our
ability to purchase natural gas futures contracts and offer fixed-price sales
contracts to our customers. We plan to structure prospective futures contracts
so that they will be accounted for as cash flow hedges under SFAS 133, but
we cannot be certain they will qualify. For more information, please read Risk
Management Activities above.
We have prepared a sensitivity analysis to estimate
our exposure to market risk with respect to our fixed price and price cap sales
contracts as of September 30, 2007. Market risk is estimated as the potential
loss resulting from a hypothetical 10.0% adverse change in the fair value of
natural gas prices. The results of this analysis, which assumes natural gas
prices are in excess of our 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
|
%
|
$
|
(0.8
|
)
|
Price cap contracts
|
|
10.0
|
%
|
$
|
(0.7
|
)
|
As of September 30, 2007 we did not have any futures
contracts outstanding.
Item 4. Controls and Procedures
Disclosure
Controls and Procedures
We maintain disclosure controls and procedures and
internal controls that are designed to provide reasonable, but not absolute,
assurance that information required to be disclosed in our Exchange Act reports
is recorded, processed, summarized and reported within the time periods
specified in the Securities and Exchange 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 as of the end of the period covered by this report. Based on the
foregoing, our Chief Executive Officer and Chief Financial Officer concluded
that our disclosure controls and procedures were effective.
Changes
in Internal Control over Financial Reporting
In addition, an evaluation was performed under the
supervision of and with the participation of our management, including our
Chief Executive Officer and Chief Financial Officer, of any change in our
internal control over financial reporting that has occurred during our last
fiscal quarter that has materially affected, or is reasonably likely to affect
materially, our internal control over financial reporting. There has been no
change in our internal control over financial reporting during our most recent
fiscal quarter that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.
25