Source: http://investors.cleanenergyfuels.com/secfiling.cfm?filingID=1047469-09-5335
Timestamp: 2017-03-26 05:16:20
Document Index: 284127962

Matched Legal Cases: ['§232', '§ 1', '§ 1', '§ 2', '§ 2', '§ 3', '§4', '§5', '§ 1', '§5', '§5', '§5']

PDF WORD XLS Clean Energy Fuels Corp. (Form: 10-Q, Received: 05/11/2009 11:02:37) QuickLinks
and posted pursuant to Rule 405 of Regulation S-T (§232,405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant
As of May 4, 2009, there were 50,238,212 shares of the registrant's common stock, par value $0.0001 per share, issued and outstanding.
Item 2.Management's Discussion and Analysis of Financial Condition and Results of
December 31, 2008 and March 31, 2009 (Unaudited)
30,920,390
Accounts receivable, net of allowance for doubtful accounts of $657,734 and $680,016 as of December 31, 2008 and March 31, 2009,
10,265,201
13,040,766
3,841,983
3,875,805
67,380,223
160,921,254
8,208,193
285,862,657
2,858,363
10,413,044
10,012,354
24,197,067
Common stock, $0.0001 par value. Authorized 99,000,000 shares; issued and outstanding 50,238,212 shares and 50,238,212 shares at December 31, 2008 and
(122,655,457
3,240,008
28,960,706
22,161,597
(73,724
(278,030
(1,243,345
(80,984
(9,146,735
(593,835
(9,721,734
(5,364,041
Clean Energy Fuels Corp. (the "Company") is engaged in the business of selling natural gas fueling solutions to its
primarily in the United States and Canada. The Company has a broad customer base in a variety of markets including public transit, refuse, airports and regional trucking. Clean Energy operates or
supplies approximately 175 natural gas fueling locations in California, Texas, Colorado, Maryland, New York, New Mexico, Nevada, Washington, Massachusetts, Georgia, Wyoming, Arizona, Ohio and Oklahoma
within the United States, and in British Columbia and Ontario within Canada. The Company also generates revenue through operation and maintenance agreements with certain customers, through building
and selling or leasing natural gas fueling stations to its customers, and through financing its customers' vehicle purchases. In April 2008, the Company opened the first compressed natural gas ("CNG")
station in Lima, Peru through the Company's joint venture, Clean Energy del Peru. In August 2008, the Company acquired 70% of the outstanding membership interests of Dallas Clean Energy, LLC
("DCE"). DCE owns a facility that collects, processes and sells renewable biomethane collected from a landfill in Dallas, Texas.
The accompanying interim unaudited condensed consolidated financial statements include the accounts of the
operations and cash flows for the three months ended March 31, 2008 and 2009. All intercompany accounts and transactions have been eliminated in consolidation. The three month periods ended
March 31, 2008 and 2009 are not necessarily indicative of the results to be expected for the year ending December 31, 2009 or for any other interim period or for any future year.
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, 2008
that are included in the Company's Annual Report on Form 10-K filed with the SEC.
On August 15, 2008, Clean Energy and Cambrian Energy McCommas Bluff LLC ("Cambrian") formed a joint venture to acquire all of the outstanding membership interests of Dallas
Clean Energy, LLC ("DCE") which owns a facility that collects, processes and sells landfill gas at the McCommas Bluff landfill located in Dallas, Texas. This acquisition enables Clean Energy to
participate in the production of pipeline quality renewable biomethane which may be used as a vehicle fuel.
indemnification claims, if any.
Note 2Acquisition (Continued)
DCE. The exercise price of the option is $368,000 for each 1%, up to $6,992,000 for the total 19%. The option may be exercised as a whole or in part (but only in 1% increments) during the
ten-year period commencing on the date which the loan made by the Company to DCE has been repaid in full.
Company borrowed $18.0 million from PlainsCapital Bank to finance its acquisition of its membership interests in DCE. The Company also obtained a $12.0 million line of
credit from PlainsCapital Bank to finance capital improvements of the DCE processing facility pursuant to a loan made by the Company to DCE and to pay certain costs and expenses related to the
acquisition and the PlainsCapital Bank loan. As of March 31, 2009, the Company had borrowed $7.8 million under the line of credit (see note 10).
Company accounted for the acquisition in accordance with SFAS No. 141,
Cambrian's minority interest, in the DCE acquisition:
was acquired with the acquisition. The fair value of the identifiable intangible asset will be amortized on a straight-line basis over the remaining life of the lease, approximately
16.5 years at the acquisition date.
not material to the Company's results of operations for the years ended December 31, 2007 and 2008.
Note 4Natural Gas Derivative Financial Instruments
The Company, in an effort to manage its natural gas commodity price risk exposures related to certain contracts, utilizes derivative financial instruments. The Company, from time to
time, enters into natural gas futures contracts that are over-the-counter swap transactions that convert its index-based
Note 4Natural Gas Derivative Financial Instruments (Continued)
supply arrangements to fixed-price arrangements. The Company accounts for its derivative instruments in accordance with SFAS No. 133,
, as amended ("SFAS 133"). SFAS 133 requires the recognition of all derivatives as either assets or liabilities in the
consolidated balance sheet and the measurement of those instruments at fair value. Historically through June 30, 2008, the Company's derivative instruments have not qualified for hedge
accounting under SFAS 133. On and after July 1, 2008, the Company has entered into futures contracts that did qualify for hedge accounting. The Company's futures contracts at
March 31, 2009 are being accounted for as cash flow hedges under SFAS 133 and are being used to mitigate the Company's exposure to changes in the price of natural gas and not for
speculative purposes. At March 31, 2009, all of the Company's futures contracts qualified for hedge accounting. The Company did not own any futures contracts during the first three months of
recorded unrealized gains of approximately $33,000 in accumulated other comprehensive income for the three month period ended March 31, 2009 related to its futures contracts. The liability for
the Company's futures contracts of approximately $621,000 at March 31, 2009 is included in accrued liabilities on the Company's condensed consolidated balance sheet at March 31, 2009.
The Company's ineffectiveness related to its futures contracts during the three month period ended March 31, 2009 was insignificant. For the three month period ended March 31, 2009, the
Company recognized losses of approximately $500,000 in cost of sales in the accompanying condensed consolidated statement of operations related to its futures contracts that did qualify for hedge
Company is required to make certain deposits on its futures contracts, should any exist. At March 31, 2009, the Company had $1.1 million of margin deposits related to
its futures contracts covering approximately 1.6 million gallons of fuel, all of which were current and recorded in prepaid expenses and other current assets in the accompanying condensed
consolidated balance sheet as of March 31, 2009.
Note 5Fixed Price and Price Cap Sales Contracts
The Company enters into contracts with various customers, primarily municipalities, to sell LNG or CNG at fixed prices, or through December 31, 2006, at prices subject to a price
cap. The contracts generally range from two to five years. The most significant cost component of LNG and CNG is the price of natural gas.
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.
Note 5Fixed Price and Price Cap Sales Contracts (Continued)
principles do not require or allow the Company to record a loss until the delivery of the gas and corresponding sale of the product occurs. When the Company enters into these fixed price or price cap
contracts with its customers, the price is set based on the prevailing index price of natural gas at that time. However, the index price of natural gas constantly changes, and a difference between the
fixed price of the natural gas included in the customer's contract price and the corresponding index price of natural gas typically develops after the Company enters into the sales contract (with the
price of natural gas having historically increased). From time to time, the Company has also entered into natural gas futures contracts to offset economically the adverse impact of rising natural gas
prices (see note 4), and prior to December 31, 2006, if the Company believed the price of natural gas would decline in the future, periodically sold such contracts.
or CNG).
Other receivables at December 31, 2008 and March 31, 2009 consisted of the following:
4,554,235
3,882,484
2,636,974
Note 7Land, Property and Equipment
Land, property and equipment at December 31, 2008 and March 31, 2009 are summarized as follows:
90,848,632
60,733,405
11,237,383
19,955,733
195,111,450
(34,190,196
Note 8Investments in Other Entities
Through March 31, 2009, the Company invested approximately $5.0 million in The Vehicle Production Group LLC ("VPG"), a company that is developing a natural gas
vehicle made in the United States for taxi and paratransit use. The Company committed to fund up to $10 million in VPG from August 2008 through March 2010. $7.5 million is a firm
commitment by the Company, and $2.5 million is contingent
on VPG not being able to raise money on more-favorable terms than the funding from the original investor group. In addition, VPG may under certain circumstances make a capital call on
investors which could require the Company to invest up to approximately $0.8 million in additional funds. The Company accounts for its investment in VPG under the cost method of accounting as
the Company does not have the ability to exercise significant influence over VPG's operations.
be converted earlier upon an acquisition of BAF. As of March 31, 2009, the $3.8 million outstanding under the Note would convert into approximately 49% of the outstanding equity
interests of BAF if fully converted. The Company may, at the Company's discretion, advance up to $2.2 million in additional funds to BAF under the Note. The Note bears interest at 5% per annum
and is due August 30, 2010.
Note 9Accrued Liabilities
Accrued liabilities at December 31, 2008 and March 31, 2009 consisted of the following:
2,771,465
In conjunction with the Company's acquisition of its 70% interest in DCE (see note 2), on August 15, 2008, the Company entered into a Credit Agreement with PlainsCapital
Bank. The Company borrowed $18.0 million (the "Facility A Loan") to finance the acquisition of its membership interests in DCE. The Company also obtained a $12.0 million line of credit
from PlainsCapital Bank to finance capital improvements of the DCE processing facility and to pay certain costs and expenses related to the acquisition and the PlainsCapital Bank loans (the "Facility
B Loan"). As of March 31, 2009, the Company had borrowed $7.8 million under the Facility B Loan. The Company may request funds up to $12.0 million under the Facility B Loan
through August 14, 2009. Interest accrues daily on the Facility A
and B Loans at the greater of the prime rate of interest for the United States plus 0.50% per annum or 5.50% per annum. The Company paid a facility fee of $300,000 in connection with the Credit
Agreement. As of March 31, 2009, the unamortized balance of the facility fee was $262,500. Amortization of the facility fee is recorded as additional interest expense in the consolidated
each month until August 15, 2013, at which time the remaining amount of the unpaid principal and interest on the Facility A Loan is due and payable.
on the unpaid principal balance of the Facility B Loans is due and payable quarterly commencing on September 30, 2008. The principal amount of the Facility B Loans is due
and payable in annual payments commencing on August 1, 2009, and continuing each anniversary date thereafter, with each such payment being in an amount equal to the lesser of twenty percent of
the aggregate principal amount of the Facility B Loan then outstanding or $2,800,000. On August 15, 2013, the remaining amount of unpaid principal and interest under the Facility B Loans is due
Note 10Long-term Debt (Continued)
as defined, of not less than $150.0 million, and a debt to equity ratio, as defined, of not more than 0.3 to 1. Beginning in the quarter ending June 30, 2009, the Company must
also maintain a debt service ratio, as defined, of not less than 1.5 to 1 at each quarter end. Effective in the fourth quarter of 2008, the Company established a lock-box arrangement with
PCB subject to the Credit Agreement. Funds from the Company's customers are remitted to the lock-box and then deposited to a PCB bank account. The remitted funds are not used to
pay-down the balance of the credit agreement. However, if the Company defaults on the Credit Agreement, all of the obligations under the Credit Agreement will become immediately due and
payable and all funds received in the Company's lock-box held by PCB will be applied to the balance due on the Facility A and B Loans. One of the events of default is the occurrence of a
"material adverse change," which is a subjective acceleration clause. Based on the guidance in Emerging Issues Tax Force Issue No. 95-22
Classification of Borrowings Outstanding under Revolving Credit Agreements That Include both a Subjective Acceleration Clause and a Lock-Box Arrangement
(EITF
No. 95-22), the Company has classified its debt pursuant to the Credit Agreement as short-term or long-term as appropriate and believes an event of default
is more than remote but not more likely than not. The Company is in compliance with the covenants as of March 31, 2009.
of the Company's bank covenants is a requirement to maintain accounts receivable balances from certain subsidiaries above $8.0 million at each quarter end during the term. To
the extent natural gas prices fall, which a significant portion of the Company's revenues are derived from, or the Company's volumes decline, the Company could violate this covenant in the future.
Beginning with the quarter ending June 30, 2009, the Company is required to maintain a debt service ratio, as defined, of not less than 1.5 to 1. To the extent the Company's operating results
do not materialize as anticipated, the Company could violate this covenant in the future. In the event the Company would violate either of these covenants, it would seek a waiver from the bank.
Credit Agreement is secured by the Company's interest in, and note receivable from, DCE (described below), certain of the Company's accounts receivable and inventory balances and 45
of the Company's LNG tanker trailers. The Company maintains $2.5 million in a payment reserve account at PCB. PCB may withdraw funds from the account to apply to the principal and interest
payments due on Facility A and B Loans. Such amount is included as restricted cash in the Company's consolidated balance sheet at March 31, 2009.
expenditures. Upon closing of the acquisition of DCE, the Company funded approximately $714,000 under the agreement. The funds were obtained as part of the initial $4.2 million funded under the
Facility B Loan with PlainsCapital Bank to the Company. Interest on the unpaid balance accrues at a rate of 12% per annum and is payable quarterly beginning September 30, 2008. The principal
amount of the loan is due and payable in annual payments commencing on August 1, 2009, and continuing each anniversary date thereafter, with each such payment being in an amount equal to the
lesser of the aggregate principal amount of the DCE Loan then outstanding or $2,800,000. On August 1, 2013, the entire amount of unpaid principal and interest under the DCE Loan is due and
payable. The principal and accrued interest balances as well as any interest income related to the DCE Loan are eliminated in the consolidated financial statements of the Company. Any event of default
by DCE on the DCE Loan
in a cross-default of the Company's Credit Agreement with PlainsCapital Bank. Events of default include failure to make payments when due, DCE's failure to perform under the provisions of its
landfill lease with the City of Dallas, DCE's violation of a covenant under its operating agreement and other standard events of default.
payments under the Facility A Loan and the Facility B Loan at March 31, 2009 are as follows:
Facility A Loan
13,878,609
17,081,024
17,489,921
7,818,397
25,308,318
Note 11Correction of Immaterial Error
Subsequent to the year ended December 31, 2008, the Company identified an error in the number of gallons it used to claim its Volumetric Excise Tax Credit ("VETC") refund. Due to
this error, the Company's revenues were understated in 2007 and overstated in 2008.
error was immaterial to previously reported amounts contained in its periodic reports. Accordingly, the Company has revised its
consolidated balance sheet as of December 31, 2008 and it intends to revise its consolidated financial statements for certain quarterly and annual periods through subsequent periodic filings.
For quarters prior to June 30, 2008, the Company's financial statements have not been revised as the net amount of the error is insignificant. The effect of recording this immaterial correction
in the statements of operations for the year ended December 31, 2008, the balance sheet as of December 31, 2008, and for the fiscal 2008 quarterly periods to be reported in subsequent
periodic filings are as follows:
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:
securities were excluded from the diluted earnings per share calculations at March 31, 2008 and 2009, respectively, as the inclusion of the securities would be
anti-dilutive to the calculation. The amounts outstanding as of March 31, 2008 and 2009 for these instruments are as follows:
9,186,904
Note 13Comprehensive Income (Loss)
The following table presents the Company's comprehensive loss for the three months ended March 31, 2008 and 2009:
Derivative unrealized gains
(6,525,501
in comprehensive loss at March 31, 2009 is approximately $386,000 of income related to the non-controlling interest in DCE.
The following table summarizes the compensation expense and related income tax benefit related to stock
recognized during the periods:
The following table summarizes the Company's stock option activity during the three months ended March 31, 2009:
4,555,370
fair value of each option is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants in 2009:
on these assumptions, the weighted average grant date fair value of options granted during the three months ended March 31, 2009 was $3.98.
Note 15Use of Estimates
The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect
The 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
with applicable federal, state, local and foreign environmental laws and regulations.
Company may become party to various legal actions that arise in the ordinary course of its business. During the course of its operations, the Company is also subject to audit by tax
authorities for varying periods in various federal, state, local, and foreign tax jurisdictions. Disputes may arise during the course of such audits as to facts and matters of law. It is impossible at
this time to determine the ultimate liabilities that the Company may incur resulting from any lawsuits, claims and proceedings, audits, commitments, contingencies and related matters or the timing of
these liabilities, if any. If these matters were to be ultimately resolved unfavorably, an outcome not currently anticipated, it is possible that such outcome could have a material adverse effect upon
the Company's consolidated financial position or results of operations. However, the Company believes that the ultimate resolution of such actions will not have a material adverse affect on the
Company's consolidated financial position, results of operations, or liquidity.
FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109" (FIN 48), requires that the Company recognize
the impact of a tax position in its financial statements if the position is more likely than not of being sustained by the taxing authority upon examination, based on the technical merits of the
position. FIN 48 requires the Company to accrue interest based on the difference between the tax position recognized in the financial statements and the amount claimed on the return. The net
interest incurred was immaterial for the three months ended March 31, 2008 and 2009. FIN 48 further requires that penalties be accrued if the tax position does not meet the minimum
statutory threshold to avoid penalties. No penalties have been accrued by the Company. The Company's unrecognized tax benefits as of March 31, 2009 are unchanged from December 31, 2008.
It is anticipated that the Company's liability for uncertain tax positions will be reduced by as much as $319,000 during the year as a result of the settlement of tax positions with various tax
tax authorities. The Company is no longer subject to U.S. examination for years before 2005, and state examinations for years before 2004.
On January 1, 2008, the Company adopted the applicable provisions of SFAS No. 157,
(SFAS 157), which defines fair value, establishes a framework for measuring fair value and enhances disclosures about fair value measurements related to financial instruments. In December 2007,
the FASB provided a one-year deferral of SFAS 157 for non-financial assets and non-financial liabilities, except those that are recognized or disclosed at
fair value on a recurring basis, at least
Note 18Fair Value Measurements (Continued)
Accordingly, the Company's adoption of SFAS 157 was limited to financial assets and liabilities.
the three months ended March 31, 2009, the Company's financial instruments consisted of natural gas futures contracts and the Series I warrants (see note 19).
The Company uses quoted forward price curves, discounted to reflect the time value of money, to value its natural gas futures contracts. The Company uses a Monte Carlo simulation model to value the
Series I warrants, which requires the Company to make estimates regarding risk-free interest rates, the volatility of its stock price, and its anticipated dividend yield. The Company's futures
contracts are recorded in accrued liabilities and the Series I warrants are recorded in other long-term liabilities in the accompanying condensed consolidated balance sheet at March 31,
following table reflects the fair value as defined by SFAS 157, of the Company's natural gas futures contracts and the Series I warrants at March 31, 2009:
Natural gas futures contracts obligation
12,550,505
Note 19Recently Adopted Accounting Changes
beginning in 2009. The adoption of SFAS 141(R) did not have a material impact on the Company's financial statements.
December 2007, the FASB issued Statement of Financial Accounting Standard No. 160,
Statementsan amendment of ARB No. 51
("SFAS 160"). SFAS 160 requires presentation of non-controlling interests in consolidated
significant influence of the subsidiary, any adjustments will be made through equity, while transactions where control changes will be accounted for through earnings. SFAS 160 was effective for
the Company on January 1, 2009. As a result of adopting SFAS 160, the Company reclassified the minority interest of DCE to the stockholders' equity section of the consolidated balance
sheet. References to minority
interest in previous financial statements are now reflected as noncontrolling interest. The adoption of this statement did not have a material impact on the Company's consolidated financial position
March 2008, the FASB issued Statement of Financial Accounting Standards No. 161,
"Disclosures about Derivative Instruments and Hedging
Activitiesan amendment of FASB Statement
Note 19Recently Adopted Accounting Changes (Continued)
No. 133"
("SFAS 161"). SFAS 161 amends and expands the disclosure requirements of FASB Statement No. 133 (SFAS 133), requiring enhanced
disclosures about the Company's derivative and hedging activities. The Company is required to provide enhanced disclosures about (a) how and why it uses derivative instruments, (b) how
derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect the
Company's financial position, results of operations, and cash flows. The Company adopted of this statement as of January 1, 2009 and the adoption did not have a material impact on its
April 2008, the FASB issued FASB Staff Position No. FAS 142-3,
a recognized intangible asset under FASB Statement No. 142,
Goodwill and Other Intangible Asset.
More specifically, FSP
statement did not have a material impact on the Company's consolidated financial statements.
June 2008, the Emerging Issues Task Force (EITF) reached a consensus in EITF No. 07-5,
Determining Whether an Instrument (or Embedded
(EITF No. 07-5). The Task Force concluded, among other things, that contingent and other adjustment features in
equity-linked financial instruments are consistent with equity indexation if they are based on variables that would be inputs to a "plain vanilla" option or forward pricing model and they do not
increase the contract's exposure to those variables. The Company's Series I warrants issued on October 28, 2008 are linked to the Company's own equity shares; however, the investor has
protective pricing features commonly referred to as "
down-round"
protection, whereby the conversion price potentially resets if the common
stock price of the Company declines after issuance. As a result of this guidance, effective January 1, 2009, the Company accounts for the Series I warrants as a derivative under FASB
Statement No. 133,
. As a result of adopting EITF No. 07-5, the
Company recorded a cumulative-effect adjustment of approximately $2.6 million to opening retained earnings and reclassed approximately $9.8 million from additional paid-in
capital to long-term liabilities on the date of adoption, January 1, 2009.
On April 3, 2009, DCE entered into a fifteen year gas sale agreement with Shell Energy North America (US), L.P. ("Shell") for the sale by DCE to Shell of biomethane
produced by DCE's landfill gas processing facility located at McCommas Bluff in Dallas Texas. The gas sale agreement calls for the sale of up to the following quantity of biomethane by DCE to Shell
April 2009 through September 2010: 4500 MMBtus per day
Note 20Subsequent Events (Continued)
Calendar year 2019 to March 2024: 6000 MMBtus per day
day of biomethane for sale as a vehicle fuel. To the extent that DCE produces volumes of biomethane in excess of the volumes sold under the agreement with Shell, DCE will either attempt to sell such
volumes at then-prevailing market prices or seek to enter into another gas sale agreement in the future. There is no guarantee that DCE will produce or be able to sell up to the maximum
prices for natural gas of $3.80 per MMBtu as quoted on NYMEX for May delivery on April 3, 2009.
requirements under the relevant renewable portfolio standard with respect to use of the biomethane in power generation. DCE is in the preliminary stages of assessing whether greenhouse gas emission
reduction credits will be generated or available for sale as a result of the landfill gas collection and pipeline quality biomethane production. Given the complex and changing standards and
DCE's landfill gas operations.
two-year average, are less than an annual average of 630,720 MMBtu per year (or 2,083 MMBtu per day).
April 28, 2009, the Company purchased certain natural gas futures contracts to attempt to hedge its exposure to cash flow variability related to the fixed-price component of
two liquefied natural gas (LNG) supply contracts for which it had submitted fixed-price bids. The Company has not been awarded the contracts; however, based on information released by the potential
customers, the Company believes it has submitted the lowest price in the competitive bidding process. The Company has also received a staff recommendation supporting its bid for the larger of the two
contracts. If the Company is successful in being awarded the supply contracts, performance is anticipated to begin on July 1, 2009 and September 6, 2009, respectively, on the two
contracts. The futures contracts have the effect of enabling the Company to purchase natural gas at fixed prices each month from July 2009 through August 2012, which is the expected fixed-price term
of the potential supply contracts. One of the supply contracts calls for the sale of approximately 12,000,000 LNG gallons annually for all three years of the contract, and the other supply contract
calls for the anticipated sale of approximately 700,000 LNG gallons in the first year, 500,000 LNG gallons in the second year and 300,000 LNG gallons in the third year of the contract. The futures
contracts cover the purchase of an average of approximately 80,000 MMBtus of natural gas per month to hedge against the cost of the fixed price LNG delivery obligations. To purchase the futures
contracts, the Company was required to make an initial margin deposit of $1,236,000. The Company may be required to make additional deposits if it incurs losses related to the futures contracts. The
Company will attempt to qualify the futures contracts for hedge accounting under SFAS No. 133, but there can be no assurances the Company will be able to do so.
Note 21Volumetric Excise Tax Credit (VETC)
The Company records its VETC credits as revenue in its condensed consolidated statements of operations as the credits are fully refundable and do not need to offset income tax
liabilities to be received. VETC revenues for the three month periods ended March 31, 2008 and 2009 were approximately $4.7 million and $4.1 million, respectively.
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations.
The following Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) should be read together with
the unaudited condensed consolidated financial statements and the related notes included elsewhere in this report. For additional context with which to understand our financial condition and results
of operations, refer to the MD&A for the fiscal year ended December 31, 2008 contained in our annual report on Form 10-K filed with the SEC on March 16, 2009, as well
as the consolidated financial statements and notes contained therein.
This MD&A and other sections of this report contain forward looking statements. We make forward-looking
factors include, but are not limited to, those discussed under the caption "Risk Factors" in this report and in our annual report on Form 10-K. In preparing this MD&A, we presume
that readers have access to and have read the MD&A in our Annual report on Form 10-K, pursuant to Instruction 2 to paragraph (b) of Item 303 of
Regulation S-K. We undertake no duty to update any of these forward-looking statements after the date of filing of this report to conform such forward-looking statements to actual
results or revised expectations, except as otherwise required by law.
processes and sells renewable biomethane collected from a landfill in Dallas, Texas.
This overview discusses matters on which our management primarily focuses in evaluating our financial condition and operating
We generate the majority of our revenue from selling CNG and LNG and providing
operations and maintenance services to our customers. The balance of our revenue is provided by designing and constructing natural gas fueling stations, financing our customers' natural gas vehicle
purchases and sales of pipeline quality biomethane produced by our DCE joint venture.
In evaluating our operating performance, our management focuses primarily on: (1) the amount of CNG and LNG
our customers at stations where we provide O&M services but do not directly
2008 and for the three months ended March 31, 2008 and 2009:
(44,462,674
Key trends in 2006, 2007, and 2008.
Vehicle fleet demand for natural gas fuels increased during the three year period ended
We believe this growth in demand was attributable primarily to the rising prices of gasoline and diesel relative to CNG and LNG during this period 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
number of fueling stations we served grew from 147 at December 31, 2004 to 173 at March 31, 2009 (a 17.7% increase). The amount of CNG and LNG gasoline gallon
prices, contributed to increased revenues during these periods. Our cost of sales also increased during these periods, which was attributable primarily to the increased costs related to delivering
more CNG and LNG to our customers and the increased price of natural gas.
On April 3, 2009, DCE entered into a fifteen year gas sale agreement with Shell Energy North America (US), L.P. ("Shell")
for the sale by DCE to Shell of biomethane produced by DCE's landfill gas processing facility located at McCommas Bluff in Dallas Texas. The gas sale agreement calls for the sale of up to the
following quantity of biomethane by DCE to Shell daily:
day of biomethane for sale as
a vehicle fuel. To the extent that DCE produces volumes of biomethane in excess of the volumes sold under the agreement with Shell, DCE will either attempt to sell such volumes at
then-prevailing market prices or seek to enter into another gas sale agreement in the future. There is no guarantee that DCE will produce or be able to sell up to the maximum volumes
called for under the agreement, and DCE's ability to produce such volumes of biomethane is dependent on a number of factors beyond DCE's control including, but not limited to, the availability and
composition of the landfill gas that is collected, the impact on DCE's operations of the operation of the landfill by the City of Dallas and the reliability of the processing plant's critical
April 28, 2009, we purchased certain natural gas futures contracts, which we refer to as the futures contracts below, to attempt to hedge our exposure to cash flow variability
related to the fixed-price component of two liquefied natural gas (LNG) supply contracts for which we have submitted fixed-price bids. We have not been awarded the contracts; however, based on
information released by the potential customers, we believe we have submitted the lowest price in the competitive bidding process. We have also received a staff recommendation supporting our bid for
the larger of the two contracts. If we are awarded the supply contracts, performance is anticipated to begin on July 1, 2009 and September 6, 2009, respectively. While we have not
received notification that we have been awarded the contracts, due to the fact that the contract prices are fixed, as well as the fact that we believe natural gas prices may rise between now and the
time we might be awarded the contracts, the derivative committee of our board of directors concluded it was advisable to purchase the futures contracts in advance of any contract award. The futures
contracts have the effect of enabling us to purchase natural gas at fixed prices each month from July 2009 through August 2012, which is the expected fixed-price term of the potential supply
contracts. One of the supply contracts calls for the sale of approximately 12,000,000 LNG gallons annually for all three years of the contract, and the other supply contract calls for the anticipated
sale of approximately 700,000 LNG gallons in the first year, 500,000 LNG gallons in the second year and 300,000 LNG gallons in the third year of the contract. The
contracts cover the purchase of an average of approximately 80,000 MMBtus of natural gas per month to hedge against the fixed price LNG delivery obligations. To purchase the futures contracts,
we were required to make an initial margin deposit of $1,236,000. We may be required to make additional deposits if we incur losses related to the futures contracts.
purchase of the futures contracts was in accordance with the revised natural gas hedging policy adopted by our board of directors in May, 2008, a complete copy of which was filed as
Exhibit 99.1 to our Form 8-K filed with the SEC on June 20, 2008, and is incorporated herein by reference.
such time as we are awarded and enter into the supply contracts, we do not anticipate trying to qualify the futures contracts for hedge accounting as cash flow hedges under SFAS
No. 133. As a result, we will be required to record directly in our statement of operations any changes in the fair market value of these contracts that may occur from April 28, 2009
through the earlier to occur of (1) our entry into the fixed-price supply contracts and success in qualifying the futures contracts for hedge accounting under SFAS No. 133, or
(2) the sale of the futures contracts. Until such time as the futures contract qualify for hedge accounting as cash flow hedges under SFAS No. 133, an increase or decrease of 10% in the
weighted average price of the futures contracts would result in a gain or loss, respectively, of approximately $1.8 million in the fair market value of the futures contracts.
we are awarded and enter into the supply contracts, (1) we will attempt to qualify the futures contracts for hedge accounting as cash flow hedges under SFAS No. 133, but
there can be no assurances we will be successful in doing so, and (2) we anticipate that we will hold the futures contracts for the duration of the relevant contract term consistent with the
revised natural gas hedging policy adopted by our board of directors in May 2008. If we are not awarded or fail to enter into either supply contract, we intend to sell the futures contracts related to
such supply contract in an orderly fashion.
purchased the futures contracts from Sempra Energy Trading Corp. pursuant to the terms of the ISDA Master Agreement dated March 23, 2006 between us and Sempra, including the
ISDA Credit Support Index to the Schedule to the ISDA Master Agreement dated March 23, 2006, which documents are attached as Exhibits 10.13 and 10.14, respectively, to the
Form S-1 Registration Statement (File No. 333-137124) we filed with the SEC on September 6, 2006. These documents are incorporated herein by reference.
Despite the recent volatility and decline in energy prices, we anticipate that, over the long term, the
estimates of total recoverable domestic reserves from producers have increased to equal 118 years of U.S. production at 2007 producing rates. The study indicated a mean level of reserves equal
to 88 years of supply at 2007 production levels. Indications were that shale gas production growth from only the major six shale plays, plus the Marcellus shale, could become 27 Billion
cubic feet per day and as high as 39 Billion cubic feet per day by 2015. Navigant has also indicated that development of the shale resources base has resulted in a substantial current surplus
of gas supply compared to demand of as much as 11 Billion cubic feet per day. These current surplus levels are 18% of annual average historical U.S. consumption levels of approximately 20 Tcf
per year making available gas supply to meet all existing markets and to meet new market requirements. Analysts believe that there is a significant worldwide supply of natural gas relative to crude
oil as well. According to the 2008 BP Statistical Review of World Energy, on a global basis, the ratio of proven natural gas reserves to 2007
gas production was 45% greater than the ratio of proven crude oil reserves to 2007 crude oil production. This analysis suggests significantly greater longer term availability of natural gas
than crude oil based on current consumption.
of Los Angeles and Long Beach. We also anticipate expanding our sales of CNG and LNG in the other markets in which we operate, including public transit, refuse hauling and airports. Consistent with
the anticipated growth of our business, we also expect that our operating costs and capital expenditures will increase, primarily from the anticipated expansion of our station network as well as the
logistics of delivering more CNG and LNG to our customers. Additionally, we have and will continue to increase our sales and marketing team and other necessary personnel as we seek to expand our
existing markets and enter new markets, which will also result in increased costs.
addition, the economic recession that began during 2008 has resulted in decreased demand for vehicle fuel generally, which reduced our sales of LNG and CNG fuel during 2008. The
disruption in the capital markets that began during 2008 and has continued into 2009 has made it more difficult for new customers to finance or invest in natural gas vehicle acquisitions. Continuing
economic contraction and reduced economic activity may reduce our opportunities to attract new fleet customers. Many governmental entities, which during 2006 through 2008 represented approximately
two-thirds of our revenues, are experiencing significant budget deficits as a result of the economic recession and may be unable to invest in new natural gas vehicles for their transit or
refuse fleets or may be compelled to reduce public transportation and services, which would negatively affect our business.
In May 2007, we completed our initial public offering of 10,000,000 shares
with PlainsCapital Bank. We borrowed $18.0 million to finance the acquisition and entered into a $12.0 million line of credit from PlainsCapital Bank to provide capital to DCE, primarily
for capital expenditures, and to pay certain costs and expenses of the acquisition and the loans. As of May 4, 2009, approximately $4.2 million is available under the line of credit from
PlainsCapital Bank to provide further capital to DCE. On September 24, 2008, we sold 319,488 shares of our common stock at a purchase price of $15.65 per share to Boone Pickens
Interests, Ltd. for proceeds of approximately $5.0 million. On November 3, 2008, we sold 4,419,192 shares of common stock and warrants exercisable for common stock to third-party
investors and received net proceeds of approximately $32.5 million.
current business plan calls for approximately $20.9 million in additional capital expenditures from April 1, 2009 through the end of 2009, primarily related to
construction of new fueling stations. In addition, we anticipate that during the remainder of 2009 we will provide approximately $0.5 million for financing natural gas vehicle purchases by our
anticipate that we will fund any capital expenditures of DCE during 2009 through our line of credit from PlainsCapital Bank. We may also elect to invest additional amounts in expansion of our
California LNG plant, station construction for new or existing customers that are not currently under contract, or for other acquisitions or investments in companies or assets in
natural gas fueling infrastructure, services and production industries. We will need to raise additional capital as necessary to fund expansion of our California LNG plant, additional station
construction, acquisitions or other capital expenditures or investments which are not budgeted for in our 2009 business plan and we anticipate we will seek to raise capital during 2009. For more
information, see "Liquidity and Capital Resources" below. Due to the continuing disruption in the capital markets, we may not be able to raise capital on terms that are favorable to existing
stockholders or at all. Any inability to raise capital may impair our ability to invest in new stations, develop natural gas fueling infrastructure and invest in strategic transactions or acquisitions
and reduce our ability to expand our business and generate increased revenues.
Volatility in operating results related to futures contracts.
Historically, we have purchased futures contracts from time to time to
2008, some of our contracts qualified for hedge accounting under SFAS No. 133 and some did not. Gains and losses related to the futures contracts that did not qualify for hedge accounting,
which appear in the line item derivative (gains) losses in our condensed consolidated financial statements, have materially impacted our results of operations in recent periods. For the years ended
December 31, 2006, 2007 and 2008, derivative (gains) losses were $78,994,947, $0 and $611,175, respectively. We have no derivative (gains) losses for the three months ended March 31,
2008 and 2009 related to futures contracts. For this reason and others, we caution investors that our past operating results may not be indicative of future results. For more information, please read
"Volatility of Earnings and Cash Flows" and "Risk Management Activities" below.
Our business and prospects are exposed to numerous risks and uncertainties. For more information, see
Factors" in Part II, Item 1A of this report.
We generate revenues principally by selling CNG and LNG and providing operations and maintenance services to our vehicle fleet
customers. For the three months ended March 31, 2009, CNG and biomethane (together) represented 71% and LNG represented 29% of our natural gas sales (on a gasoline gallon equivalent basis). To
a lesser extent, we generate revenues by designing and constructing fueling stations and selling or leasing those stations to our customers. Substantially all of our operating and maintenance revenues
stations. In 2006, we began providing vehicle finance services to our customers.
We sell CNG through fueling stations located on our customers' properties and through our network of public access fueling stations. At
vehicles. Our CNG sales are made primarily through contracts with our fleet customers. Under these contracts, pricing is determined primarily on an index-plus basis, which is calculated by
adding a margin to the local index or utility price for natural gas. CNG sales revenues based on an index-plus methodology increase or decrease as a result of an increase or decrease in
the price of natural gas. We sell a small amount of CNG under fixed-price contracts and also provide price caps to certain customers on their index-plus pricing arrangement. Effective
January 1, 2007, we ceased offering price-cap contracts to our customers, but we will continue to perform our obligations under price-cap contracts we entered into
before January 1, 2007. We will continue to offer fixed price contracts as appropriate and consistent with our natural gas hedging policy that was revised in May 2008. Our fleet customers
typically are billed monthly based on the volume of CNG sold at a station.
remainder of our CNG sales are on a per fill-up basis at prices we set at the pump based on prevailing market conditions. These customers typically pay using a credit card at the
station. In April 2008, we opened our first CNG station in Lima, Peru through our joint venture Clean Energy del Peru.
We sell substantially all of our LNG to fleet customers, who typically own and operate their fueling stations. We also sell a small
including a one-year renewal period beginning April 1, 2010 that one of our customers is entitled to should they choose to exercise such renewal. This
renewal period, if exercised, would obligate us to sell the customer approximately 2.1 million LNG gallons subject to a price cap of $7.50 per MMbtu on the SoCal Border Index. We will continue
to offer fixed price contracts as appropriate and consistent with our natural gas hedging policy adopted in May 2008. Our LNG contracts provide that we charge our customers periodically based on the
volume of LNG supplied.
From October 1, 2006 through December 31, 2009, we may receive a Volumetric Excise Tax Credit ("VETC") of $0.50 per
gasoline gallon equivalent of CNG and $0.50 per liquid gallon of LNG that we sell as vehicle fuel. Based on the service relationship we have with our customers, either we or our customers are able to
claim the credit. We record these tax credits as revenues in our condensed consolidated statements of operations as the credits are fully refundable and do not need to offset tax liabilities to be
received. As such, the credits are not deemed income tax credits under SFAS No. 109. In addition, we believe the credits are properly recorded as revenue because we often incorporate the tax
credits into our pricing with our customers, thereby lowering the actual price per gallon we charge them. 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.
We generate a 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. We include the volume of fuel dispensed at the stations at which we
provide O&M services in our calculation of aggregate gallon equivalents sold.
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.
In 2006, we commenced offering vehicle finance services for some of our customers' purchases of natural gas vehicles or the conversion
required to purchase if our customer fails to purchase the vehicle as anticipated. As of March 31, 2009, we have not generated significant revenue from vehicle finance activities.
In August 2008, we acquired 70% of the outstanding membership interests of DCE for a purchase price of $19.6 million including
2008 and for quarter ended March 31, 2009, DCE generated approximately $1.8 million and $0.6 million, respectively, in revenue from sales of biomethane, all of which is included
in our condensed consolidated statements of operations.
Our earnings and cash flows historically have fluctuated significantly from period to period based on our futures activities, as all
December 31, 2007, March 31, 2008 and March 31, 2009 related to our futures contracts. In accordance with our natural gas hedging policy, we plan to structure all subsequent
futures contracts as cash flow hedges under SFAS No. 133, but we can not be certain that they will qualify. See "Risk Management Activities" below. If the futures contracts do not qualify for
hedge accounting, we could incur significant increases or decreases in our earnings based on fluctuations in the market value of the contracts from period to period.
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
specified maintenance level, our broker will issue a margin call that requires us to restore the balance. Consequently, these payments could significantly impact our cash balances. At March 31,
2009, we had $1.1 million on deposit in margin accounts.
Our credit agreement with PlainsCapital Bank ("Credit Agreement") requires us to comply with certain covenants. We may not incur
indebtedness or liens except as permitted by the Credit
or declare or pay dividends. We must maintain, on a quarterly basis, minimum liquidity of not less than $6.0 million, accounts receivable balances, as defined, of not less than
$8.0 million, consolidated net worth, as defined, of not less than $150.0 million, and a debt to equity ratio, as defined, of not more than 0.3 to 1. Beginning in the quarter ending
June 30, 2009, we must also maintain a debt service ratio, as defined, of not less than 1.5 to 1 at each quarter end. Effective in the fourth quarter of 2008, we established a
lock-box arrangement with PCB subject to the Credit Agreement. Funds received from our customers are remitted to the lock-box and then deposited to a PCB bank account. The
remitted funds are not used to pay-down the balance of the credit agreement. However, if we default on the Credit Agreement, all of the obligations under the Credit Agreement will become
due and payable and all funds received in our lock-box held by PCB will be applied to the balance due on the Credit Agreement. One of the events of default is the occurrence of a "material
adverse change," which is a subjective acceleration clause. Based on the guidance in Emerging Issues Tax Force Issue No. 95-22
of Borrowings Outstanding under Revolving Credit Agreements That Include both a Subjective Acceleration Clause and a Lock-Box Arrangement
covenants as of March 31, 2009.
the quarter ending June 30, 2009, we are required to maintain a debt service ratio, as defined, of not less than 1.5 to 1. To the extent our operating results do not materialize as planned, we
could violate this covenant in the future. In the event we violate either of these covenants, we would seek a waiver from the bank.
Our risk management activities, including the revised natural gas hedging policy adopted by our board of directors in February 2007 and
annual report on Form 10-K for the year ended December 31, 2008, which discussion is incorporated herein by reference.
expected to hedge effectively our exposure to cash flow variability related to such fixed-price sales contracts entered into after the date of the policy. The summary of the policy described above
does not purport to be complete and is qualified in its entirety by reference to the copy of the policy previously filed.
of this price component will vary based on the anticipated volume to be covered under the fixed-price sales contract.
For the first quarter of 2009, there were no material changes to the "Critical Accounting Policies" discussed in Part II,
Item 7 (Management's Discussion and Analysis of
Financial Condition and Results of Operations) of our annual report on Form 10-K for the year ended December 31, 2008.
Statement of Operations Data::
Net loss attributable to Clean Energy Fuels Corp. (18.1
Revenue increased by $0.3 million to $30.2 million in the three months ended March 31, 2009, from
in the three months ended March 31, 2008. We experienced a $5.1 million
in station construction revenues between periods primarily due to the completion of a CNG station for the Orange County Transportation District. This increase was offset by a decrease in our
average price per gallon we charged between periods. Our effective price per gallon was $1.14 in the three months ended March 31, 2009, which represents a $0.29 per gallon decrease from $1.43
in the three months ended March 31, 2008. The decrease was primarily due to the decreased price of natural gas in the first quarter of 2009, upon which a significant amount of our revenues are
based. Revenue also decreased between periods as we recorded $4.1 million of revenue related to fuel tax credits in the first quarter of 2009, compared to $4.7 million in the first
quarter of 2008. These gas sales decreases were offset by the increase in the number of gallons delivered between periods from 17.6 million gasoline gallon equivalents to 18.3 million
gasoline gallon equivalents. The increase in volume was primarily from an increase in biomethane sales and CNG sales of 0.9 million and 0.5 million gallons, respectively. The biomethane
volume related to our 70% share of the biomethane sales of DCE. Two of our new transit customers (Regional Transportation Commission of Nevada and Regional Transit Authority of Ohio) and one of our
new refuse customers (Brookhaven Carters) together accounted for 0.4 million of the CNG volume increase. Offsetting these increases is a 0.7 million gallon decrease in LNG volumes, which
was primarily due to the loss of a portion of the City of Phoenix LNG supply contract that began July 1, 2008.
Cost of sales decreased by $0.8 million to $21.6 million in the three months ended March 31, 2009, from
$22.4 million in the three months ended March 31, 2008. Our cost of sales primarily decreased between periods as a result of our effective cost per gallon declining by $0.35 per gallon
to $0.93 in the three months ended March 31, 2009, primarily due to the decreased price of natural gas in the first quarter of 2009. Offsetting this decreases was a $0.7 million increase
in costs related to delivering more volume between periods. We also experienced a $4.6 million increase in station construction costs between periods.
Derivative (gain) loss.
We recorded a derivative loss of $0.2 in the first quarter of 2009 upon the adoption of EITF No. 07-5
during the period that requires us to mark-to-market our Series I warrants (see note 19 to our condensed consolidated financial statements contained elsewhere
herein) at the end of each reporting period.
Selling, general and administrative expenses were consistent between periods. Our marketing
$1.4 million between periods as we did not incur certain
advertising costs related to the Ports of Los Angeles and Long Beach and to support the Clean Alternative Fuels Act in California in the first quarter of 2009 as we did in the first quarter of 2008.
The decrease was offset by $1.0 million increase in stock option expense between periods, primarily due to options granted to our employees in December 2008 and January 2009. We also
experienced a $0.4 million increase in salaries and benefits between periods related to the hiring of additional employees. Our employee headcount increased from 128 at March 31, 2008 to
138 at March 31, 2009.
Depreciation and amortization increased by $1.5 million to $3.6 million in the three months
March 31, 2009, from $2.1 million in the three months ended March 31, 2008. This increase was primarily related to additional depreciation expense in the three months ended
March 31, 2009 related to increased property and equipment balances between periods, primarily related to our expanded station network and our California LNG plant. Our March 31, 2009
amortization amount also includes amortization of the City of Dallas Landfill lease that we acquired in connection with our acquisition of DCE on August 15, 2008.
Interest income (expense), net, decreased by $872,000 to $33,000 of expense for the three months ended
March 31, 2009. This decrease was primarily the result of a decrease in interest income in the three months ended March 31, 2009 due to lower average cash balances on hand during the
three months ended March 31, 2009. We also incurred interest expense of
in the first quarter of 2009, net of amounts capitalized, related to the debt we incurred to acquire our interest in DCE in August 2008 that we did not incur in the first quarter
There was no significant change in other income (expense), net, between the three months ended
Equity in gains (losses) of equity method investee.
Equity in gains (losses) of equity method investee increased by $162,000 to a
$17,000 gain for
the three months ended March 31, 2009 related to our 49% interest in our Peruvian joint venture.
Noncontrolling interest in net income.
During the three months ended March 31, 2009, we recorded $0.4 million of income for
noncontrolling interest in the net income of DCE. The noncontrolling interest represents the 30% interest of our joint venture partner. The results of DCE's operations have been included in the
consolidated financial statements since August 15, 2008, the date of acquisition.
Historically, our principal sources of liquidity have consisted of cash provided by operations and financing activities, cash and cash
equivalents, the issuance of common stock, sometimes in association with the exercise of certain warrants that were callable at our option, and in 2006 a revolving line of credit with Boone Pickens,
our majority stockholder. In May 2007, we completed our initial public offering of 10,000,000 shares of common stock at a public offering price of $12.00 per share. Net cash proceeds from the initial
public offering were approximately $108.5 million, after deducting underwriting discounts, commissions and offering expenses. On August 15, 2008, in connection with our acquisition of
70% of the membership interests of DCE, we entered into a credit agreement with PlainsCapital Bank pursuant to which we have borrowed $18.0 million under a term loan and an additional
$7.8 million (as of March 31, 2009) under a line of credit (see note 10 to the accompanying condensed consolidated financial statements). On September 24, 2008, we sold
319,488 shares of our common stock at a price of $15.65 per share to Boone Pickens Interests, Ltd. for proceeds of approximately $5.0 million. On November 3, 2008, we sold
4,419,192 units of common stock and warrants for $7.92 per unit and we raised net proceeds of approximately $32.5 million after deducting offering costs.
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 may also seek to acquire
companies or assets in the natural gas fueling infrastructure, services and production industries. We financed our operations in the first three months of 2009 primarily through cash on hand.
March 31, 2009, we had total cash and cash equivalents of $30.9 million, compared to $36.3 million at December 31, 2008.
provided by operating activities was $1.7 million for the three months ended March 31, 2009, compared to cash used in operating activities of $5.7 million for
the three months ended March 31, 2008. The increase in operating cash flow resulted primarily from increased collections of accounts and other receivables between periods of $4.2 million
and a $4.2 million net return of LNG truck deposits between periods. Offsetting these increases was a $2.4 million increase in accounts payable and accrued expense
payments between periods. The remaining changes primarily resulted from changes in working capital balances, which were mostly due to timing differences related to the various cash flows between
used in investing activities was $9.7 million for the three months ended March 31, 2009, compared to $44.8 million for the three months ended March 31,
2008. Our purchases of property and equipment were $9.1 million during the first three months of 2009 compared to $14.8 million for the same period in 2008. We made an additional
investment during the first three months of 2009 of $0.6 million in the Vehicle Production Group, LLC, a company developing a CNG taxi and a paratransit vehicle. In the first three
months of 2008, we purchased $42.6 million of short-term investments with our initial public offering proceeds from May 2007, of which $12.5 million matured or were sold
during the period. We did not have any short-term investments during the first three months of 2009.
provided by financing activities for the three months ended March 31, 2009 was $2.7 million, compared to $62,000 for the three months ended March 31, 2008. In
February 2009, we borrowed an additional $3.1 million from PlainsCapital Bank to fund capital expenditures for DCE's landfill plant upgrade. This increase in cash was offset by repayment of
capital lease obligations and long-term debt of $0.4 million
futures positions, the level of any outstanding indebtedness and the interest we are obligated to pay on this indebtedness, our capital expenditure requirements (which consist primarily of station
construction, LNG plant construction costs, and the purchase of LNG tanker trailers and equipment) and any merger or acquisition activity.
Our current business plan calls for approximately $20.9 million in additional capital expenditures from April 1, 2009
through the end of 2009, primarily related to construction of new fueling stations. In addition, we anticipate that during the remainder of 2009 we will provide approximately $0.5 million for
developing CNG paratransit vehicles and taxis. Through May 4, 2009, we
have provided our joint-venture subsidiary DCE with approximately $4.4 million in financing under our loan agreement with DCE and we anticipate that we will provide up to approximately
$2.9 million in additional loan financing to DCE during the remainder of 2009 for additional capital expenditures and expenses. Financing provided to DCE is not included in our 2009 capital
expenditure business plan as we anticipate that we will fund all additional financing we provide to DCE through our $12.0 million Facility B loan with PlainsCapital Bank, which has
approximately $4.2 million in remaining available credit as of May 4, 2009. We intend to fund our principal liquidity requirements, other than our loan to DCE, through cash and cash
equivalents and cash provided by operations; however, we may pursue station construction opportunities that are not currently under contract or in our 2009 capital expenditure plan or seek to acquire
or invest in companies or assets in the natural gas fueling infrastructure, services and production industries. We may also decide to invest in expanding our California LNG plant or other LNG
production assets. We anticipate that we will seek to raise additional capital during 2009 to provide funding for any such acquisitions, strategic transactions, increases in station construction
activity, expansion of our California LNG plant or other unanticipated capital expenditures. Due to the continuing disruption in the capital markets, we may not be able to raise capital on terms that
are favorable to existing stockholders or at all. Any inability to raise capital may impair our ability to invest in new stations, develop natural gas fueling infrastructure and invest in strategic
transactions or acquisitions and reduce our ability to invest in our business and generate increased revenues.
credit agreement with PlainsCapital Bank requires that we comply with certain covenants, as detailed in footnote 10 of our condensed consolidated financial statements contained
elsewhere herein. One of the covenants requires that we maintain accounts receivable balances from certain subsidiaries
$8.0 million at each quarter-end during the term. To the extent natural gas prices continue to fall, which would result in decreased revenues, or our volumes sold decline, we
could violate this covenant in the future. Also, beginning with the quarter ending June 30, 2009, we are required to maintain a debt service ratio, as defined, of 1.5 to 1. Should our operating
results not materialize as planned, we could violate this covenant in the future. If we were to violate a covenant, we would seek a waiver from the bank, which the bank is not obligated to grant. If
the bank does not grant a waiver, all of the obligations under the credit agreement will become immediately due and payable and $2.5 million of our funds held by PlainsCapital Bank would be
applied to the balance due on the PlainsCapital Bank loans. We also would be unable to use the PlainsCapital line of credit to fund our loan to DCE if this were to occur. We were in compliance with
all of the covenants as of March 31, 2009.
The following represents the scheduled maturities of our contractual obligations as of March 31, 2009:
Long-term debt and capital lease obligations(a)
33,383,763
7,594,617
21,808,289
3,594,125
4,883,504
10,167,672
64,281,022
16,977,550
14,181,242
26,691,793
table above because the obligation is contingent on the completion of construction of the LNG plant, which is anticipated to occur in the second quarter of 2009.
of our obligations to fund various fueling station construction projects, net of amounts funded through March 31, 2009, and excluding
contractual commitments related to station sales contracts.
At March 31, 2009, we had the following off-balance sheet arrangements:
outstanding surety bonds for construction contracts and general corporate purposes totaling $5.6 million,
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.
have entered into contracts with two vendors to purchase LNG that require us to purchase minimum volumes from the vendors. One of the contracts expires in June 2009 and the
other contract expires in June 2011. The minimum commitments under these two contracts are included in the table set forth under "Take-or-pay" LNG purchase contracts above. In
October 2007, we entered into a contingent take-or-pay contract from an LNG plant that is not included in the table above as it is contingent on the LNG plant being
constructed. We anticipate construction of the plant will be completed in the second quarter of 2009.
operations began December 1, 2008, and the
payments for this lease are included in "Operating lease commitments" in the "Contractual Obligations" table set forth above.
sales-type leases for accounting purposes, which result in our customers, the lessees, reflecting the property and equipment on their balance sheets.
We are subject to market risk with respect to our sales of natural gas, which has historically been subject to volatile
domestic governmental regulation and relations.
gas costs represented 60% of our cost of sales for 2008 and 43% of our cost of sales for the three months ended March 31, 2009. Prices for natural gas over the
nine-year and three-month period from December 31, 1999 through March 31, 2009, based on the NYMEX daily futures data, have ranged from a low of $1.65 per Mcf to a high of
$19.38 per Mcf. At March 31, 2009, the NYMEX index price of natural gas was $4.07 per Mcf.
actual price of natural gas we pay at the delivery point.
contracts that did not qualify for hedge accounting and we had two derivative contracts to hedge two fixed supply contracts that did qualify for hedge accounting. During the three month period ended
March 31, 2009, we had certain futures contracts that did qualify for hedge accounting.
certain they will qualify. For more information, please read "Risk Management Activities" above.
have prepared a sensitivity analysis to estimate our exposure to market risk with respect to futures contracts we hold as of March 31, 2009 to hedge the fixed-price component
of two LNG supply contracts. If the price of natural gas were to fluctuate (increase or decrease) by 10% from the price quoted on NYMEX on March 31, 2009 ($4.07 per Mcf), we could expect a
corresponding fluctuation in the value of the contracts of approximately $82,000.
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports we
file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms and that such
information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required
disclosure. We carried out an evaluation, under the supervision of and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness
of the design and operation of our disclosure controls and procedures. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and
procedures were effective as of the end of the period covered by the report.
There were no changes in our internal control over financial reporting that occurred during the period covered by this Quarterly Report
on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
We may become party to various legal actions that arise in the ordinary course of our business. We are currently engaged in commercial
litigation with an LNG supplier but we do not believe the outcome of the litigation will have a material adverse effect on our consolidated financial position or results of operations. During the
course of our operations, we are also subject to audit by tax authorities for varying periods in various federal, state, local, and foreign tax jurisdictions. Disputes may arise during the course of
such audits as to facts and matters of law. It is impossible at this time to determine the ultimate liabilities that we may incur resulting from any lawsuits, claims and proceedings, audits,
commitments, contingencies and related matters or the timing if these liabilities, if any. If these matters were to be ultimately resolved unfavorably, an outcome not currently anticipated,
it is possible that such outcome could have a material adverse effect upon our consolidated financial position or results of operations. However, we believe that the ultimate resolution of such
actions will not have a material adverse affect on our consolidated financial position, results of operations, or liquidity.
The risk factors included in our December 31, 2008 annual report on Form 10-K
continue to apply to us, and describe risks and uncertainties that could cause actual results to differ materially from the results expressed or implied by the forward-looking statements contained in
this Quarterly Report. The discussion below includes updated risk factors that could materially affect our business and results of operations. Except as discussed in the risk factors below, there have
not been any material changes from the risk factors previously described in our December 31, 2008 annual report on Form 10-K.
Failure to comply with the terms of our Credit Agreement with PlainsCapital Bank could impair our rights in Dallas Clean Energy, LLC ("DCE")
and other secured property.
August, 2008 we acquired a 70% interest in DCE, which manages a biomethane production facility at the McCommas Bluff landfill in Dallas, Texas and holds a
lease to the associated landfill gas development rights. We borrowed $18.0 million from PlainsCapital Bank to fund the acquisition and obtained a $12 million line of credit from
PlainsCapital to pay certain costs and expenses of the acquisition and finance capital improvements of the gas processing plant through a loan made by us to DCE. We have used $7.8 million of
the line of credit from PlainsCapital Bank as of March 31, 2009. To secure our obligations under the Credit Agreement, we granted PlainsCapital Bank a security interest in 45 of our LNG tanker
trailers, certain accounts receivable and inventory, and our note receivable from, and our membership interests in, DCE. Our credit agreement with PlainsCapital Bank requires that we comply with
certain covenants, as detailed in footnote 10 of our condensed consolidated financial statements contained elsewhere herein. One of the covenants requires that we maintain accounts receivable balances
from certain subsidiaries above $8.0 million at each quarter-end during the term. To the extent natural gas prices continue to fall, which would result in decreased revenues, or our
volumes sold decline, we could violate this covenant in the future. Also, beginning with the quarter ending June 30, 2009, we are required to maintain a debt service ratio, as defined, of 1.5
to 1. Should our operating results not materialize as planned, we could violate this covenant in the future. If we were to violate a covenant, we would seek a waiver from the bank, which the bank is
not obligated to grant. If the bank does not grant a waiver, all of the obligations under the credit agreement will become immediately due and payable and $2.5 million of our funds held by
PlainsCapital Bank would be applied to the balance due on the PlainsCapital Bank loans. We also would be unable to use the PlainsCapital line of credit to fund our loan to DCE if this were to occur.
We anticipate raising debt or equity capital to fund increased capital expenditures beyond those included in our 2009 capital budget and for any
potential strategic transactions, and an inability to access the capital markets may impair our ability to expand our business
anticipate that, in order to fund capital projects beyond those included in our 2009 capital budget and to pursue potential strategic transactions as
opportunities arise (which were not included in our 2009 capital budget), we will need to pursue additional equity or debt financing, which may not be available on terms favorable to us or at all. Our
original 2009 capital plan anticipated $31.6 million of capital expenditures during 2009 and no amounts for acquisitions. While we believe that we have sufficient cash to fund our original 2009
capital plan during the remainder of the year, we anticipate that we will need to raise debt or equity capital during 2009 to have sufficient funds available to pursue strategic transactions and
capital expenditures beyond our 2009 capital budget. We may pursue equity or debt financing options including, but not limited to, equipment financing,
convertible promissory notes or commercial bank financing. Recent economic turmoil and severe lack of liquidity in the debt capital markets and volatility and rapidly falling prices in the equity
capital markets have severely and adversely affected capital raising opportunities. If we are unable to obtain debt or equity financing in amounts sufficient to fund any additional capital
expenditures, strategic transactions or unanticipated expenses, we will be forced to suspend or curtail our capital expenditure program or we may not pursue opportunities for strategic transactions,
which would limit our ability to expand our business. In addition, the terms, conditions and prices of any equity or debt issuance may be dilutive to existing stockholders or poorly received in the
investment community, which could cause the price of our commons stock to drop.
On October 28, 2008, the Company entered into a Placement Agent Agreement (the "Placement Agent Agreement") relating to the sale
and issuance by the Company to select investors of up to 4,419,192 units (the "Units"), with each Unit consisting of (i) one share of the Company's common stock, par value $0.0001 per share,
(ii) a warrant to purchase 0.75 shares of Common Stock (the "Series I Warrant"), and (iii) a warrant to purchase up to 0.2571 shares of Common Stock (the "Series II
Warrant"). Our offering of common stock and warrants was effected through a Registration Statement on Form S-3 (File No. 333-152306) that was declared effective
by the Securities and Exchange Commission on July 29, 2008. The price of each Unit was $7.92 per Unit. The transaction closed on November 3, 2008 and the Company issued 4,419,192 shares
of common stock, Series I Warrants to purchase up to 3,314,394 shares of Common Stock, and Series II Warrants to purchase up to 1,136,364 shares of Common Stock. As of
December 31, 2008, all of the Series II Warrants have been exercised. The Company received approximately $32.5 million after deducting the placement agents' fees and other
offering expenses. As of March 31, 2009, we have used $1.6 million of the net proceeds from this offering for construction and installation of CNG and LNG stations.
Third Amendment to Credit Agreement among the registrant Clean Energy and PlainsCapital Bank.*
Certification of Richard R. Wheeler, Chief Financial Officer, pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities and Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of
CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES INDEX
Clean Energy Fuels Corp. and Subsidiaries Condensed Consolidated Balance Sheets December 31, 2008 and March 31, 2009 (Unaudited)
Clean Energy Fuels Corp. and Subsidiaries Condensed Consolidated Statements of Operations For the Three Months Ended March 31, 2008 and 2009 (Unaudited)
Clean Energy Fuels Corp. Condensed Consolidated Statements of Cash Flows For the Three Months Ended March 31, 2008 and 2009 (Unaudited)
CLEAN ENERGY FUELS CORP. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
THIS THIRD AMENDMENT TO CREDIT
AGREEMENT (herein called the Amendment) is made as of May 5, 2009 by and
among CLEAN ENERGY FUELS CORP., a Delaware corporation (CEF), and CLEAN
ENERGY, a California corporation (Clean Energy; CEF and Clean Energy together
are the Borrowers), and PLAINSCAPITAL BANK, a Texas state chartered bank (Lender).
WHEREAS, the Borrowers and
Lender entered into that certain Credit Agreement dated as of August 15,
2008, as amended by that certain First Amendment to Credit Agreement dated as
of February 13, 2009 and that certain Second Amendment to Credit Agreement
dated as of March 12, 2009 (as amended, supplemented, or restated to the
date hereof, the Original Credit Agreement), for the purpose and
consideration therein expressed, whereby Lender became obligated to make loans
to the Borrowers as therein provided; and
Lender desire to amend the Original Credit Agreement as set forth herein;
consideration of the premises and the mutual covenants and agreements contained
herein and in the Original Credit Agreement, in consideration of the loans
which may hereafter be made by Lender to the Borrowers, and for other good and
§ 1.1. Terms Defined in the Original Credit
. Unless the context otherwise
requires or unless otherwise expressly defined herein, the terms defined in the
Original Credit Agreement shall have the same meanings whenever used in this
§ 1.2. Other Defined Terms
. Unless the context otherwise requires, the
following terms when used in this Amendment shall have the meanings assigned to
them in this Section 1.2.
means this Third Amendment to Credit Agreement.
 means the Original Credit Agreement as amended hereby.
AMENDMENTS TO ORIGINAL CREDIT AGREEMENT
§ 2.1. Permitted Liens
. The definition of Permitted Liens in Section 1
of the Original Credit Agreement is hereby amended to include new sub-sections (m) and
(n) that read as follows:
(m) Liens on property of
the Borrowers or their Subsidiaries granted by the Borrowers or their
Subsidiaries in connection with contractual purchase rights existing under any
fueling station construction agreements of Borrowers or their Subsidiaries,
provided that such Liens cover only the property subject to such contractual
purchase rights; and
(n) Liens granted on
property of the Borrowers or their Subsidiaries the acquisition of which by
Borrowers or their Subsidiaries is funded in whole or in part by any government
or non-profit entity funding program or grant award.
§ 2.2. Accounts
. Section 7.11 of the
Original Credit Agreement is hereby amended and restated in its entirety to
Section 7.11 Accounts
Receivable. As of the end of each
calendar quarter, the aggregate amount of Accounts of the Restricted Persons
will not be less than $8,000,000.
§ 3.1 Effective Date
. This Amendment shall become effective as of
the date first above written when and only when:
(a) Lender shall have received, at Lenders
office, this Amendment and the Consent and Agreement, each duly executed and
delivered and in form and substance satisfactory to Lender.
(b) The Borrowers shall
have paid, in connection with the Loan Documents, all fees and reimbursements
to be paid to Lender pursuant to any Loan Documents, or otherwise due Lender
and including fees and disbursements of Lenders attorneys.
§4.1 Representations and Warranties of
. In order to induce
Lender to enter into this Amendment, each Borrower represents and warrants to
Lender that:
representations and warranties contained in Article V of the Credit
Agreement are true and correct at and as of the time of the effectiveness
hereof, except to the extent that the facts on which such representations and
warranties are based have been changed by the extension of credit under the
Borrower is duly authorized to execute and deliver this Amendment and is and
will continue to be duly authorized to borrow monies and to perform its
obligations under the Credit Agreement. Such Borrower has duly taken all
corporate action necessary to authorize the execution and delivery of this
Amendment and to authorize the performance of the obligations of such Borrower.
execution and delivery by such Borrower of this Amendment, the performance by
such Borrower of its obligations hereunder and the consummation of the
transactions contemplated hereby do not and will not conflict with any
provision of law, statute, rule or regulation or of the organizational
documents of such Borrower, or of any material agreement, judgment, license,
order or permit applicable to or binding upon such Borrower, or result in the
creation of any lien, charge or encumbrance upon any assets or properties of
such Borrower. Except for those which
have been obtained, no consent, approval, authorization or order of any court
or governmental authority or third party is required in connection with the
execution and delivery by such Borrower of this Amendment or to consummate the
duly executed and delivered, each of this Amendment and the Credit Agreement
will be a legal and binding obligation of the Borrowers, enforceable in
accordance with its terms, except as limited by bankruptcy, insolvency or
similar laws of general application relating to the enforcement of creditors
rights and by equitable principles of general application.
§5.1 Ratification of
. The Original Credit
Agreement as hereby amended is hereby ratified and confirmed in all
respects. Any reference to the Credit
Agreement in any Loan Document shall be deemed to be a reference to the
Original Credit Agreement as hereby amended. The execution, delivery and effectiveness of this Amendment shall not,
except as expressly provided herein, operate as a waiver of any right, power or
remedy of Lender under the Credit Agreement, the Notes, or any other Loan
Document nor constitute a waiver of any provision of the Credit Agreement, the
Notes or any other Loan Document.
§ 1.3. Survival of
. All representations,
warranties, covenants and agreements of each Borrower herein shall survive the
execution and delivery of this Amendment and the performance hereof, including
without limitation the making or granting of the Loans, and shall further
survive until all of the Obligations are paid in full. All statements and agreements contained in
any certificate or instrument delivered by any Borrower hereunder or under the
Credit Agreement to Lender shall be deemed to constitute representations and
warranties by, and/or agreements and covenants of, such Borrower under this
§5.3 Loan Documents
. This Amendment is a Loan Document, and all
provisions in the Credit Agreement pertaining to Loan Documents apply hereto.
§5.4 Governing Law
. This Amendment shall be governed by and
construed in accordance the laws of the State of Texas and any applicable laws
of the United States of America in all respects, including construction,
§5.5 Counterparts; Fax
. This Amendment may be separately executed in
counterparts and by the different parties hereto in separate counterparts, each
of which when so executed shall be deemed to constitute one and the same
Amendment. This Amendment may be validly
executed by facsimile or other electronic transmission.
AMENDMENT AND THE OTHER LOAN DOCUMENTS
PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS OF THE
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been intentionally left blank.
Amendment is executed as of the date first above written.
CLEAN ENERGY FUELS CORP., as a Borrower
CLEAN ENERGY, as a Borrower
PLAINSCAPITAL BANK, as the
/s/ Ronald C. Berg
President, Turtlecreek
[SIGNATURE PAGE TO THIRD AMENDMENT TO CREDIT
Andrew J. Littlefair, certify that:
have reviewed this Form 10-Q of Clean Energy Fuels Corp.;
Richard R. Wheeler, certify that:
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, each of the undersigned hereby certifies in his capacity as the
specified officer of Clean Energy Fuels Corp. (the Company) that, to the best of his knowledge, the quarterly report of the Company on Form 10-Q for the fiscal quarter ended
March 31, 2009 fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, and that the information contained in such report
fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods presented in the financial statements included in such
certification accompanies this Report on Form 10-Q pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed filed by the Company
for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Such certification will not be deemed to be incorporated by reference into any filing under
the Securities Act of 1933, as amended, or the Exchange Act, except to the extent that the Company specifically incorporates it by reference.
CERTIFICATION REQUIRED BY SECTION 1350 OF TITLE 18 OF THE UNITED STATES CODE